ML12157A265

New England Coalition, Inc Contention 3 Prefiled Exhibits NEC-JH_54-NEC-JH_61

ML12157A265
Person / Time
Site:	Vermont Yankee
Issue date:	04/28/2008
From:	Hopenfeld J - No Known Affiliation
To:	Karlin A, Wendy Reed, Richard Wardwell Atomic Safety and Licensing Board Panel
References
50-271-LR, ASLBP 06-849-03-LR
Download: ML12157A265 (120)

Text

DOCKETED April 29, 2008 (8:00 a.m.)

OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF UNITED STATES NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:

Alex S. Karlin, Chairman Dr. Richard E. Wardwell Dr. William H. Reed In the Matter of )

)

ENTERGY NUCLEAR VERMONT YANKEE, LLC ) Docket No. 50-271-LR and ENTERGY NUCLEAR OPERATIONS, INC. ) ASLBP No. 06-849-03-LR (Vermont Yankee Nuclear Power Station) )

NEW ENGLAND COALITION, INC.

CONTENTION 3 PREFILED EXHIBITS NEC-J[ -154- NEC-JH_61 April 28, 2008 Oc~ b.s- 0S

NEC-JH_54 Assessment of Proposed Program to Manage Aging of the Vermont Yankee Steam Dryer Due to Flow-Induced Vibrations Dr. Joram Hopenfeld 1724 Yale Place Rockville, MD 20850 (301) 801-7480 April 25, 2008

TABLE OF CONTENTS I. Basic Concepts ....................................................... 1 II. B ackgroun d .............................................................................. .. ....... 1 III. D ryer F ailu res ................................................ ....................................... 2 IV. Entergy's Proposed Steam Dryer Aging Management Plan Program ........................ 3 V. Assessment of Proposed Steam Dryer Aging Management Plan ............................. 4 A . B asic C onsiderations ...................................................................... 4 B. Aging Management Requirements ...................................................... 5 V I. C onclusions ................................................................................... 6

I. Basic Concepts NEC's Contention Three addresses Entergy's plan to manage aging of the Vermont Yankee (VY) steam dryer due to flow-induced vibration, mechanical vibratioh resulting from.interactions between the elastic forces in the dryer and the dynamic forces of the flowing steam. Such vibrations can result when the dryer or one of its components sheds vortices due to ý boundary layer flow separation at the surface. These vortices create pressure oscillations near the dryer, causing the dryer to vibrate. When the natural frequency of the dryer, or one of its components is close to the shedding frequency of the vortex, the resulting vibrations can cause catastrophic damage to the dryer.

The frequencies at which vortices are shed from a structure are correlated with a nondimensional number called theStrouhal number; S = f D/V, f is the frequency, D is a dimensional length, V is the flow velocity, S is an empirical number that depends on the Reynolds number. For high Reynolds numbers and simple geometries, such as a cylinder, S is approximately a constant, making the frequency'directly proportional to the flow velocity. For a given structure, a small change in velocity may cause the v'ortex shedding frequency to increase and approach the natural frequency of the structure.

II. Background.

The steam dryer has no safety functions. However, the structural integrity of the dryer must be maintained such that the generation-of loose parts is prevented during normal operation, transients1 and accident events.

A public safety hazard would result if the dryer was damaged and some of its parts broke loose and were transported by flow or gravity to other areas of the reactor system. Loose parts may block flow channels in the reactor core, block spray cooling nozzles, or prevent the main steam isolation valves

("MSIVs") from isolating the system during loss of coolant accidents

("LOCA"). This is a direct threat to public health and safety and in violation of General Design Criteria GDC 1 and Draft GDC -40 and -42, 10 CFR Part 50, Appendix A insofar as they require that protection must be provided against the dynamic effects of loss of coolant accidents, LOCA.

'A "transient" is the plant response to a change in power level.

At the beginning of 2006, the operating power at the Vermont Yankee plant was increased by 20%. This also increased the velocities by 20%.

Other plants where the velocity was increased experienced crack formation in the steam dryer as described in GE SIL No. 6442, as discussed further below. Consequently, Entergy installed strain gauges to monitor the condition of the dryer during accession to power. The strain -gauges were installed in the main steam line (MSL) to monitor pressure fluctuations within the main steam flow. The data were then used as inputs to an acoustic circuit model (ACM) to calculate pressure loads on the steam dryer and the resulting stress in steam dryer components using a finite element

-model (FEM).3 III. Dryer Failures GE Nuclear Entergy Service Information Letter, SIL No. 644, Revision 1 (November 9, 2004) provides a summary of experience with dryer failures following power uprates.4 Failures due to both localized high and low frequency pressure loading occurred on dryers at two different power plants. In both cases, the failures at different locations on the dryer occurred from high cycle fatigue. The small pressure fluctuations in the steam lines (3-4 psi) indicate that even small pressure fluctuations on the dryer can generate altering stresses that exceed the endurance limit at some dryer locations. 5 This is important because it indicates that in order to predict whether the dryer will crack one must first know what the loads are on the dryer at various locations.

The history of steam dryer cracking at the VY plant indicates that Entergy's program to date of visual inspection and moisture monitoring have 2 Exhibit NEC-JH_55.

3 See, ML060050028, Safety Evaluation by Office of Nuclear Reactor Regulation Related to Amendment No. 229 to Facility Operating License No. DPR28, Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc., Vermont Yankee Nuclear Power Station Docket 50-271 at § 2.2.6.2.1.

4 Exhibit NEC-JH_55 at 1-5, Appendices A, B; See also, Exhibit NEC-JH 56.

5 Exhibit NEC-JH- 5 5.

2

been ineffective in identifying cracking at the time it occurs, when it occurs in between inspections. 6 General Electric evaluated crack formation in the dryer during the last refueling outage RF026.7 GE believes that all the cracks were caused by intergranular stress corrosion cracking ("IGSCC").

However, GE did not rule Out the possibility of continued crack growth by fatigue.

IV. Entergy's Proposed Steam Dryer Aging Management Plan Program Entergy has represented that its aging management program for the steam dryer during the period of extended operations will consist exclusively of periodic visual inspection and monitoring of plant parameters as described in GE-SIL-644, and will not involve the use of any analytical tool to estimate stress loads on the steam dryer.8 Entergy described its proposed program as follows:

The aging management program for the VY steam dryer during the twenty-year license renewal period will consist of well-defined monitoring and inspection activities that are defined in GE SIL-644 guidelines and are identical to those being conducted during the current post-EPU phase. Steam dryer integrity will be monitored continuously via operator monitoring of certain plant parameters. VY Off-normal Procedure ON-3178 alerts the operators that -any of the following events could be indicative of reactor internals damage and/or loose parts generation: a) a sudden drop in main steam line flow > 5%; b) > 3 inch difference in reactor vessel water level instruments; c) sudden drop in steam dome pressure > 2 psig. In addition, periodic measurements of moisture carryover will be evaluated in accordance with the requirements of GE-SIL-644. This monitoring program will,continue for the entire license renewal period. The inspection activities will include 6 Exhibit NEC-JH_57; Exhibit NEC-JH_58 at 4-5; Exhibit NEC-JH_59; Exhibit NEC-JH_60.

7Exhibit NEC-JH_59.

8 Exhibit NEC-JH_61 at ¶¶ 23-24.

3 2

visual inspections of the steam dryer every two refueling outages consistent with GE and BWR Vessel Internals Program (VIP) requirements. The inspections will focus on areas that have been repaired, those where flaws exist, and areas that have been susceptible to cracking based on reactor operating experience throughout the industry.

The aging management plan for the license renewal period, consisting of the monitoring and inspection activities described above, does not depend on, or use, the CFD and ACM computer codes or9the [finite element modeling] conducted using those codes.

GE- SIL-644 recommends visual inservice inspections during each. refueling outage, but does not require any measurements that could indicate whether existing cracks in the dryer grow in number or length. Visual inspection of the dryer is done with a camera only in accessible areas.

V. Assessment of Proposed Steam Dryer Aging Management Plan A. Basic Considerations The steam dryer is susceptible to two-types of cracks, (a) stress corrosion cracks, ("SC") and (b) fatigue cracks. Even when one can measure with Eddy Current the density or depth of existing SC cracks, there is no way of predicting how fast such cracks would reach a critical size and then propagate through the wall very rapidly given the presence of sufficiently high loads. Fatigue cracks are usually initiated at points of high stress concentrations which were formed during the fabrication process.

Fatigue cracks may be slow to initiate, but once initiated they propagate very fast when exposed to alternating stresses of sufficient magnitude and frequency. Because of the two-stage process of crack formation, when one does not find cracks during inspection, there is absolutely no reason why such cracks would not start propagating once the plant is restarted. The steam dryer problem at VY is serious because we already know that the 20%

9 Id.; see also, License Renewal Application § 3.1.2.2.11.

4

increase in velocity increased the potential for the creation of fluctuating pressure loadings. Small changes in local velocity may cause pressure frequencies of local pressure fluctuations to approach the natural frequency of the dryer.

There were problems in the interpretation of the strain gauge data during the accession to 120% at VY and the ACRS questioned the validity of the analytical models.' 0 Following the accession to power, Entergy removed the instrumentation that was used to monitor the pressure fluctuations within the dryer."

B. Aging Management Requirements A sufficient steam dryer aging management plan at VY must include both 1) visual inspection of the steam dryer, and 2) some means of estimating and predicting stress loads on the steam dryer, establishing dryer flow induced vibration load fatigue margins, and demonstrating that stresses on the dryer at selected locations will fall below ASME fatigue limits. The ability to accurately assess and predict stress loads that may act on the dryer during the fuel cycle is essential to ensure the dryer's structural integrity.

The visual inspection program and any repairs to the dryer must be informed by knowledge of dryer loads. Plant experience (see Part II1, above) demonstrates that an aging management plans that consists solely of parameter monitoring, and partial visual inspection, uninformed by knowledge of dryer loading, will not be sufficient.

Plant parameter monitoring is not effective to prevent the generation of loose parts that can damage safety-related plant components. Most parameter monitoring (moisture, steam flow, water level, dome pressure) may indicate the formation of only those steam dryer cracks that increase moisture carryover; those cracks that do not lead to significant moisture carryover may continue to grow undetected. Moisture monitoring only indicates that a failure has occurred; it does not prevent ihe failure from occurring. In fact, GE-SIL-644 states the limitations of parameter monitoring as follows: "monitoring steam moisture content and other reactor

'0 See, ML060040431, Letter to Nils J. Diaz from Graham B. Wallis re. Vermont Yankee Extended Power Uprate (January 4, 2006) at 5.

"Exhibit NEC-JH_61 at ¶27.

5

parameters does not consistently predict imminent dryer failure nor will it preclude the generation of loose parts.." 2 VI. Conclusions For the above-stated reasons, I believe that the operation of the steam dryer, as currently intended by Entergy, is a direct threat to public health and safety and is in violation of GDC 1 and Draft GDC -40 and -42 insofar as, they require that protection must be provided against the dynamic effects of a LOCA. I also believe that it was a mistake to remove the instrumentation for the determination of the loads on the dryer. Instead of eliminating all instruments, VY should have improved the analytical tools for predicting, the loads on the dryer, perhaps by conducting additional scaling test at GE at the San Jose facility.

Entergy must formulate a new plan to manage steam dryer cracking before entering the extended period of operation. The plan should be reviewed by a competent party with no financial ties to Entergy.

12 Exhibit NEC-JH_ at 6.

6

NEC-JH_55 SIL GE NuclearEnergy Services Information'Letter BWR steam dryer integrity SIL No. 644 SIL No. 644 ("BWR/3 steam dryer.failure"), / monitoring recommendations for all BWR plants Revision 1 issued August 21, 2002, described an event at a based on these observations.. In that the BWR/3 that involved the failure of a steam dryer occurrence of fatigue cracking. has been November 9, 2004 cover plate resulting in the generation of loose observed in several BWRs, this revision contains parts, which Were ingested into a main steam inspection and monitoring recommendations that line (MSL). The most likely cause of this event apply to all plants. SIL No. 644 Revision 1 was identified as high cycle fatigue caused by a voids and supercedes SIL No. 644 and SIL No.

flow regime instability that resulted in localized 644 Supplement 1.

high frequency pressure loadings near the MSL Discussion nozzles. SIL No. 644 Supplement I, issued September 5, 2003, described a second steam Instances of fatigue cracking in the steam dryer dryer failure that occurred at the same BWR/3 hood region have been observed recently in approximately one year following the initial several BWR plants. The cracking has led to steam dryer failure.This second failure: failure of the hood and the generation of loose occurred at a different location with the root parts in two BWRJ3 plants. Details of the cause identified as high cycle fatigue resulting cracking in these plants are described below.

from low frequency pressure loading. SIL No. These observations have potential generic 644 included focused recommendations. For significance for all BWR steamdryers that will BWR/3-style steamdryers, it recommended be discussed in the generic implications section monitoring steam moisture content (MC) and below.

other reactor parameters, and for those plants B WR/3-Style Dryer Observations operating atgreater than the original licensed thermal power (OLTP), it recommended Lower horizontal cover plate failure occurred in inspection of the cover plates at the next a BWR/3 in 2002. In this failure, almost the refueling outage. SIL No. 644 Supplement I entire lower horizontal cover plate came broadened the earlier recommendations for completely loose, with some large pieces falling BWR/3-style steam dryer plants and provided down onto the steam separators and one piece additional recommendations for BWR/4 and being ingested into the main steamline and later steam dryer design plants planning to or 'lodging in the flow restrictor. This failure was already operating at greater than OLTP. accompanied by a significant increase in moisture content, along withchanges in other Following this revised guidance, inspections monitored reactor parameters. The cause of this were performed on plants operating at OLTP, failure was attributed to the higher fluctuating stretch uprate (5%), and extended power uprate pressure loads at extended power uprate (EPU) conditions. These inspections indicate that operation. In particular, there may have been a steam dryer fatigue cracking can also occur in potential resonance condition. between a high jplants operating at OLTP. frequency fluctuating pressure loading (in the The purpose of this Revision .1 to SIL No. 644 is 120-230 Hz range) and the natural frequency of to describe additional significant fatigue the cover plate. Appendix A provides a more cracking that has been observed in steam dryer detailed description of this event.

hoods subsequent to the issuance of SIL No. 644 The same BWR/3 experienced extensive Supplement I and to provide inspection and through-wall cracking in the outer bank hood on 2

2 SIL No. 644 Revision 1 - page 2 the 900 side in May 2003. On the opposite side through the unsupported section of the veirtical of the steam dryer (2700 side), incipient cracking braces, thus overstressing the vertical braces.

was observed on the inside of the outer hood In October 2003 and December 2003, cover plate. Several internal braces were, inspections were made of the steam dryers of the detached and found on top, of the steam sisterunits to the BWR/3s described above at separators. No damage was found on the inner another site. These units had also been banks of the dryer. Again, the failure was operating at EPU conditions. Incipient cracking accompanied by a significant increase in was observed on the inside of the outer hood; moisture content. Of the other monitored vertical plates on each of the outer dryer banks.

reactor parameters, only the flow distribution At one location, the cracking had grown between the individual steamlines was affected. through-wall. The cracking was also attributed The cause of this failure was attributed to high to high cycle fatigue resulting from low cycle fatigue resulting from low frequency frequency pressure loading.

oscillating pressure loads (<50 Hz) of higher amplitude at EPU operation and the local stress In March 2004, inspections were performed of concentration introduced by the internal brackets the repairs made to the BWR/3 dryer in 2003.

that anchor the diagonal internal braces to the Incipient fatigue cracks were found atthe tips of dryer hoods. Appendix B provides a more the external reinforcing gussets that were added.

detailed description of this event. as part of the 2003 repairs. Fatigue cracks were also found in tie bars that were reinforced during InNo-vember 2003, a hood failure occurred in the 2003 repairs. Thecracking in these repairs the sister unit to the BWR/3 that had was attributed to local stress concentration experienced the previously noted failures. This introduced by the as-installed repairs.. In both unit was also operating at EPU conditions. The cases, the local stress concentrations had not.

observed hood damage and associated root cause been modeled in sufficient detail in the analyses determination were virtually the same as the that supported the repair design. Fatigue cracks May 2003 failure described above. During the were also found in perforated plate insert event, the moisture content exceeded the modifications that were made in 2002 as part of previously defined action level- However, the.. the extended power uprate implementation.

monitored plant parameters (primarily individual These cracks were also attributed to the steamline flow rates) showed only subtle displacements and stresses imposed by the dryer changes and were Well within the previously banks that caused the tie bar cracking.

defined action levels for the plant.. This failure

-resulted'in the generation of looseparts from the In April 2004, inspections were made of a outer vertical hood plate. In addition, BWR/3-style dryer (square hood) in a BWR/4 inspections during the repair outage showed plant in preparation for implementing an fatigue cracking in the inner hood vertical braces extended power uprate during the upcoming.

below where the lower ends of the diagonal cycle. This inspection found cracking at two braces were attached. The cracking of these diametricallyopposed locations on the exterior braces was attributed to poor fit-up of the parts steam dam near the lifting lug. Both cracks during the dryer fabrication. The diagonal were similar-in length. The cause of the braces should have terminated on the vertical cracking was not identified. It has been braces where they were butted up against the postulated that'the crack initiation was.due to drain trough, which would have transferred the high residual stresses generated during the dryer diagonal brace loads directly to the drain trough. fabrication process. The structural analysis of Instead, the diagonal braces terminated on the the steam' dryer for EPU conditions did not vertical braces above the top of the drain trough predict these locations as highly susceptible to and the diagonal brace loads were transmitted fatigue cracking. Two other symmetrical

SIL No. 644 Revision 1

• page 3 locations'in the steam dryer that experienced ihe inspection of this location was recommended by same loading conditions did not exhibit any SIL No. 644 Supplement 1. The hood cracks at evidence of cracking. These observations point the other four plants occurred early in plant life, to the likelihood of the presence of an additional within the first three or four cycles of operation.

contributing factor aside from the pressure loads In-plant vibration testing of one of the cracked during normal operation. Specifically, the dryers. showed that the dynamic pressure evidence indicates that a high residual stress oscillations were high 'enough that the 1/8" hood condition was probably developed by the to end plate weld was vulnerable to fatigue' original dryer fabrication welding sequence. cracking at pre-uprate power levels. The hood Other "cold spring" type loading could also have crack at the subject BWR/5 occurred after been generated during the fabrication 'process.' approximately 16 years of operation, the last After the cracking developed, the. residual nine of which were at a 5% stretch uprate power stresses would have been relieved and the crack level: While power uprate operation does growth would have subsided. increase the loading on the dryer, the length of operating'time at uprated power levels before the B WR/5-Style Dryer Observation cracking was observed indicates that the weld, In March 2004, inspection of the steam dryer at was not grossly overstressed and that power a BWR/5 revealed a fatigue crack in the hood uprate was only a secondary factor in the panel to end plate weld. The hood crack cracking observed at the subject BWR/5.

occurred in the weld joint between the 1/8" B WR Fleet OperatingHistory curved hood and the 1/4" end plate on the.

second'dryer bank. This particular weld location Steam dryer cracking has been observed is vulnerable to fatigue cracking because of the throughout the BWR fleet operating history..

small weld size associated with the thin 1/8" The operating environment has a significant hood material.- Fabrication techniques (e.g., influence on the susceptibility of the dryer to feathering the 1/8" plate during fit-up) may cracking. Most of the steam dryer is located in further reduce the weld size. Fatigue cracking the steam space with the lower half of the skirt has been observed in the second bank hood-end immersed in reactor water at saturation plate weld at several other plants with the curved temperature. 'These environments are highly BWR/4-5 hood design at OLTP power levels. oxidizing and increase the susceptibility to An undersized weld was determined to be the IGSCC cracking.. Average steam flow velocities root cause of the cracking observed in at least' through the~dryer vanes at rated conditions are two of the plants. Incorporating lessons learned relatively modest (2 to 4 feet per second).

-from the weld cracks at the other plants, the However, local regions near the steam outlet dryer for this BWR/5 was built with an nozzles may be continuously exposed to steam additional 1/4" fillet weld on the inside of the flows in excess of 100 feet per second* Thus, hood-end plate joint. This weld extended as there is concern for fatigue cracking resulting high up in the hood as was practical for the from flow-induced vibration and fluctuating welder to make (approximately 50") and pressure loads acting on the dryer.

spanned the probable initiation location for the In addition to the recent instances described earlier cracks.' The weld crack at the subject above, steam' dryer cracking has been observed BWR/5 occurred in the upper part of the 1/8" in the following components at several BWRs:

weld, above this reinforced section.

dryer hoods, dryer hood end plates, drain The weld joint between the 1/8" curved hood channels, support rings, skirts, tie bars, and.

and the 1/4" end plate n the second dryer bank lifting rods. These crack experiences have is a known high stress location for the BWR/4-5 predominately occurred during OLTP curved hood dryer design; therefore, periodic conditions, and are briefly described below.

SIL No. 644 Revision I - page 4 Dryer Hood Cracking analysis of potential sources of stress on the welds indicate that high cycle fatigue initiated As discussed above, outer hood cracking has the cracks in drain channel welds. With the occurred recently in square hood-design dryers.

internal dryer inspections performed following Additionally, other hood cracking has occurred the issuance of SIL No. 644, similar cracking in the BWR operating fleet. Cracking of this has been observed in the internal drain channels type was first found in BWR/2s in the inner of BWR/3-type steam dryers. Typically, drain

,banks. These hood cracks were attributed to channel cracks have been repaired by replacing high cycle fatigue. Other cracking has since and adding rqinforcement weld material, stop-been observed in other types of dryers including drilling the crack tip, or by replacing the drain BWR/4s and attributed to high cycle fatigue as channels.

well. Susceptible plants were typically reinforced with weld material or plates. Support Ring Cracking Dryer End Plate cracking Support ring cracking has been found, in many BWRs. Cracking has been found in at least 19 Cracking has been detected in end plates of the plants, ranging from BWR/4s to BWR/6s. The dryer banks at several BWRs. These cracks cause of cracking has been IGSCC with a have been attributed to IGS.CC based on the potential contributor being the cold working of location and morphology of the cracks. These the support ring during the fabrication process.

cracks have been followed over several cycles These cracks are typically monitored for growth.

and shown to be stable when operating To date, no repairs have been necessary since conditions (power levels) are not changed.

cracks havereached an arrested state.

Typically no repairs have been necessary..

Skirt Drain Channel Cracking Skirt cracking has been found along with drain Drain channel cracking has been found in all channel cracking. These cracks are either due to types of BWRs. This cracking has been IGSCC or could be related to fatigue due to primarily categorized as being attributable to imposed local loads on the dryer. The cracking fatigue, although many cracks have been has also been found in the formed channel

• attributed to IGSCC. The steam dryers were section of the dryer. The complex structural originally fabricated using Type 304 stainless dynamic mode shapes 6f the dryer skirt, the

.steel, a material susceptible to sensitization by

• stiffness added by the drain and guide channels, welding processes and prone to crack initiation and residual weld stresses all contribute to the

• in the presence of cold work. Drain channel cracking observed in these components.

cracking has been associated with at least 17 Cracking in the dryer skirt region has been plants. The occurrence of the cracking observed in plants operating at both OLTP and prompted GE to issue SIL No. 474 ("Steam uprated power levels. Typically, repairs have Dryer Drain Channel Cracking" issued October been implemented at the time that cracking was.

26, .1988) after cracks were discovered in the found. J drain channel attachment welds during routine visual examination of dryers at several BWR/4, Tie Bar Cracking.

5 and 6 plants. The cracks generally were Fatigue cracking has been observed in tie bars of through the throat of vertical welds that attach plants operating at both OLTP and uprated the side of the drain channel to the exterior of power levels. In most cases, the potential for the 0.25-inch thick dryer skirt. The cracks were cracking is related to the cross section of the tie as long as 21 inches. The cracks are thought to bar itself because the tie bar must withstand the have originated at the bottom of the drain displacements and stresses imposed by the dryer channel where there is maximum stress in the banks. Typically, repairs have been welds. The appearance of the cracking and

SIL No. 644 Revision 1.e page 5 implemented at the time that cracking was The hood crack-initiation at the BWR/3s found. described above occurred at these high stress locations. Also, the undersized hood-to-end.

Lifting Rod plate welds on the BWR/5 curved hood Several plants have exhibited damage in the dryers have cracked in several plants.

lifting rods. This cracking has often been in tack o The actual dryer fabrication may have welds or in lateral brackets and has been introduced stress concentrations that may.

attributed to fatigue, lead to fatigue cracking. The poor fit-up of Other Crack Locations the diagonal and vertical braces in the.

BWR/3 dryer led to the cracking of the Other locations have also exhibited cracking.

vertical braces. Feathering of the 1/8" plate These locations include the level screws or during fit-up, and the corresponding leveling screw welds, seismic blocks, dryer bank reduction' in weld area, was considered a end plates and internal attachment welds, contributing factor in the through-wall vertical internal'hood angle brackets and bottom plates. cracking of the hood-end plate weld in one of the BWR/5-style dryers. Residual.

GenericImplications stresses or "cold spring" introduced during The steam dryer is a non-safety Component. the fabrication sequence may also lead to However, the structural integrity of the dryer crack initiation.

must be maintained such that the generation of " The fabrication quality for each dryer may loose parts is prevented during normal operation, vary from one unit to the next, even if the transients, and accident events. With the dryers were built' by the same .fabricator.to exception of the significant outer hood cracking the same specifications.

at the two BWRJ3 plants, the dryer cracking observed in the BWR fleet to date is unlikely to. o. The design of dryer repairs and result in the generation of loose parts provided modifications should consider the local that a periodic inspection program is in place. stress concentrations that may be introduced

• However, given that the steam, dryers operate in by the modification design or installation.

an environment that. is conducive to crack' Repairs and modifications to the dryer should be inspected at each outage following initiation and that many plants are pursuing the installation until structural integrity of power uprates and operating license extensions, further cracking in steam dryers should be the repairs and modifications can be anticipated. Therefore, the material condition of confirmed.

the dryer should be actively managed to ensure o Steam dryers are susceptible to IGSCC due that structural integrity is maintained throughout to the material and fabrication techniques the life of the dryer. used in the dryer construction.' Weld heat affected zone material is likely to be The-experience described above has several generic implications with respect to the sensitized. Many dryer assembly welds susceptibility of steam dryersto fatigue or have crevice areas at the weld root, which were not'sealed from the reactor IGSCC cracking.

environment. Cold formed 304 stainless o Fatigue cracking may result from stress steel dryer parts were generally' not solution concentrations inherent in the design of the annealed after forming and welding.

dryer. The design of the BWRP3-style steam .Therefore, steam dryers are susceptible to dryers with a square hood and internal IGSCC.

'braces results in maximum stresses where the internal braces attach to the outer hood.

pge 1*

Rvison 44 o.

SIL SIL No. 644 Revision 1 - page 6 Parameter monitoring programs had been Recommended Actions:

previously recommended with the intent of GE Nuclear Energy recommends that owners of detecting structural degradation of the steam GE BWRs consider the following:

dryer during plant operation. The experience described above also has generic implications A. For all plants:

with respect to monitoring reactor system Al. Perform a baseline visual inspection of all parameters during operation for the purposes of susceptible locations of the steam dryer detecting steam dryer degradation. within the next two scheduled refueling o The November 2003 BWR/3 hood failure outages. Inspection guidelines showing the demonstrated that monitoring steam susceptible locations for each dryer type are moisture content and other reactor provided in Appendix C.

parameters does not consistently predict a. Repeat the visual inspection of all imminent dryer failure nor will it preclude susceptible locations of the steam dryer the generation of loose parts. Monitoring, is -at least once every two refueling still useful in that it does allow identification outages.

of a degraded dryer allowing appropriate

b. For BWR/3-style steam dryers with action to be taken to minimize the damage to the dryer and the potential for loose parts internal braces in the outer hood that are generation. operating above OLTP, repeat the visual inspection of all susceptible locations of 0 Monitoring the trends in parameter values the steam dryer during every refueling may be more important than monitoring the outage..

parameter values against absolute action

'thresholds. An unexplained change in the c. Flaws left "as-is" should be inspected trend or value of a parameter, particularly during each scheduled refueling outage steam moisture content or the flow until it has been demonstrated that there distribution between individual steamlines is no further crack growth and the flaws may be an indication of a breach in the dryer have stabilized.

hood, even though the absolute value of the Note: This recommendation does not parameter is still within the normal supercede'the inspection schedules for experience range. existing flaws for which plant-specific o Statistical smoothing techniques such as evaluations already exist.

calculating running averages using a large d. Modifications and repairs to cracked quantity of samples may be necessary to components should be inspected during eliminate the process noise andallow the each scheduled refueling outage until changes in the trend to be identified. the structural integrity of the o An experience base should be developed for. modifications and repairs hasbeen each plant that correlates the changes in demonstrated. Once structural integrity of any modifications and repairs has monitored parameters to changes in plant operation (rod patterns, core flow, etc.) in been demonstrated, longer inspection order to be able to distihguish the intervals for these locations may be indications of a degraded dryer from normal justified.

variations that occur during the operating Note: This recommendation does not cycle. supercede the inspection schedules for existing modifications or repairs for

• which plant-specific evaluations already exist.

SIL No. 644 Revision I

• page 7 A2. Implement a plant parameter monitoring B 1. Perform a baseline visual inspection of the program that measures moisture content and steam dryer at the outage prior to initial other plant parameters that may be operation above the OLTP or current power influenced by steam dryer integrity. Initial level. Inspection guidelines, for each dryer monitoring should be performed at. least type are provided in Appendix C.

weekly. Monitoring guidelines are provided B2. Repeat the visual inspection of all in Appendix D.

susceptible locations of the.steamdryer A3. Review drawings of the steam dryer to during each subsequent refueling outage.

determine if the lower cover plates are less Continue the inspections at each refueling' than 3/8 inch thick or if the attachment outage until at least two full operating cycles welds are undersized (less than the lower at the final uprated power level have been cover plate thickness). If this is the case, achieved. After two full'operating cycles at and the plant. has operated above OLTP, the -final uprated power level, repeat the review available visual inspection records to visual inspection of all susceptible locations determine if there are any pre-existing flaws of the steam dryer at least once every two in the cover plate and/or the attachment refueling outages. For BWR/3-style steam welds. dryers with internal braces in the outer hood, repeat the visual inspection of all susceptible B. In addition, for plants planning on increasing the operating power level above locations of the steam dryer during every refueling outage..

the OLTP or above the current established uprated power level (i.e., the plant has B3. Once structural integrity.of any repairs and operated at the current power level for modifications has been demonstrated and several cycles.with no indication of steam any flaws left "as-is" have been shown to dryer integrity issues), the recommendations have stabilized at the final uprated power presented in A (above) should be modified. level, longer inspection intervals for these

.as follows: locations may be justified.

To receive additional information on this subject Issued by or for assistance in implementing a recommendation, please contact your local GE Bernadette Onda Bohn, Program Manager Nuclear Energy Representative. Service Information Communications This SIL pertains only to GE BWRs. The GE Nuclear Energy conditions under which GE Nuclear Energy 3901 Castle Hayne Road issues SILs are stated in SIL No. 001 M/CLIO Revision 6, the provisions of which are Wilmington, NC 28401 incorporated into this SIL by reference.

Productreference BI I -Reactor Assembly B 13)- Reactor System

SIL No. 644 Revision I

• page 8 Appendix A 2002 BWRI3 Event On June 7, 2002, while operating at approximately 113% of OLTP, the BWR/3 experienced a mismatch between the "A" and "B" reactor vessel level indication channels, a loss of approximately 12 MWt, and a reactor pressure decrease. Following the event, measurement indicated that the moisture content had increased by a factor of 10 (to a value of 0.27%). The reactor pressure decrease, reactor vessel level indication mismatch, and increase in moisture content comprised a set of concurrent indications suggestinga possible failure of the steam dryer. It was evaluated that there were no safety concerns associated with the observed conditions, and the plant continued to operate after implementing several compensatory measures.(e.g.,reactor water level setpoint adjustments, increased frequency of moisture content measurements).

Following the. initial event, additional short duration (several minutes to 1/2hour) perturbations occurred and the moisture content continued to increase. When the moisture content increased to approximately 0.7%, the power level was reduced to approximately 97% of OLTP. At this reduced power, the frequency of the plant perturbations decreased, along with the moisture content. Given the stable plant response at this lower power, the power was increased to 100% OLTP approximately one week later.

On June 30, subsequent to the power reduction to the OLTP level, a step change increase in the reactor steam dome pressure was noted. No changes in turbine control valve positions or pressure in the turbine steam chest.were observed.. Several additional perturbations occurred over the following week with the reactor steam dome pressure continuing to increase (to a total of 15 to 20 psi above normal. conditions) along with a divergence of the measured total main steam line (MSL) flows, compared to the total feedwater flow. The plant was shut down on July 12 to inspect the steam dryer.

Inspection Results:.

Inspection of the steam dryer revealed that a 1/4-inch stainless steel cover plate measuring

. approximately 120" x 15" had failed near the MSL "A" and "B" nozzles (Figure A-]). The failure of this cover plate allowed steam to bypass the dryer banks and exit through the reactor MSL nozzles, causing the observed increase in moisture content. The majority of the cover plate was found as a single piece on top of steam separators. However, a piece of the cover plate (approximately 16"x 6")

had failed and was found lodged in and partially blocking the MSL "A" flow venturi contributing to the MSL flow imbalance and water levelperturbations. Several smaller loose pieces (believed to have come from a startup pressure sensor bracket which may have been knocked off by the cover.

plate) were located at the turbine, stop valve strainer basket. -Minor gouges and .scratches from the transport of foreign material were noted in the "A" steam nozzle cladding, the main steam piping and the MSL "A" flow venturi. All loose pieces were recovered. No collateral damage to other reactor vessel components was observed.

The cover plate was welded in place as part of the original equipment dryer assembly. No known prior repairs had been made to the cover plate. The cover plate is not connected or adjacent to the dryer modification performed at the previous outage; all flow distribution plates installed as part of the dryer modification were intact in the as-installed condition.

SIL No. 644 Revision I

• page 9 M'etallurgicalEvaluation:

Preliminary laboratory analysis has been completed. The main crack originated from the bottom side of the cover plate and propagated upward through both the plate base metal and weld metal. The transgranular, as opposed to intergranular, nature of the fracture surface and the relative lack of crack branching indicated that the failure was not caused by stress-corrosion cracking. The lack of macro and micro ductility features in and near the fracture indicated the cracking occurred over a period of timeand not due to a mechanical overload. Additionally, there was no evidence that the failure was a result of an original manufacturing defect. Based on the available evidence, the most probable cause of the cover plate cracking was mechanical, high cycle fatigue.

Root Causes:

The results of the metallurgical analysis confirmed that the failure mechanism ishigh cycle fatigue. The cause of this high cycle fatigue is believed to be flow induced vibration. At this time there are two probable root causes of the cover plate failure:

.1. Increased pressure oscillations on the steam dryer due to the increased steam'flows at extended power uprate conditions, aggravated by the potential presence of a pre-existing crack in the cover plate.

2. A flow regime instability that results in localized, high cycle pressure loadings near the MSL nozzles. When the natural frequency of the installed cover plate coincides or nearly coincides with the frequency of the cyclic pressure forcing function, and the acoustic natural frequency of

• the steam zone, the resulting resonance or resonances can lead to high vibratory stresses and eventual high cycle fatigue failure of the cover plate:

CorrectiveActions:

The cover plates on both sides of the dryer have been replaced with IA-inch continuous plates (this eliminates two intermediate welds on the original plates). The fillet weld connecting the plate to the support ring was increased to %-inch and the weld to thevertical face of the dryer hood was increased to 1/2-inch. The plant has been returned to service with interim, enhanced monitoring of moisture

• content, reactor steam dome pressure, MSL flow rates and reactor water level. As an additional measure, the.plant has implemented dynamic response monitoring of the MSLs to determine if higher flow induced vibration occurs as the steam flow is increased.

r-

SIL No. 644 Revision I - page 10 Figure A-I: Location of the 2002 Lower Cover Plate Failure

SIL No. 644 Revision I - page 11.

Appendix B 2003 BWR/3 Event On April 16, 2003, with the plant operating at extended power uprate (EPU) conditions, an inadvertent opening of a pilot operated relief valve (PORV) occurred. The unit was shut down and the*PORV replaced.. On May 2, 2003, following return to EPU conditions, a greater than four-fold increase in the moisture content was measured. 'The moisture content continued to gradually increase until it exceeded a pre-determined threshold of 0.35% on May 28, 2003. The.power level was reduced to pre-EPU conditions that resulted in a moisture content reduction to 0.2%. The moisture content remained steady at this value following the power reduction with no significant changes in other reactor operating parameters observed by the operators.

A detailed statistical evaluation of key plant parameters concluded that a subtle change in the MSL flows had occurred following the April 16, 2003 PORV event. Based on this information, concurrent with the moisture content increase, the utility elected to shut down the unit on June 10, 2003 and perform a steam dryer inspection.

Inspection results A detailed visual inspection of the accessible external and internal areas of the steam dryer revealed significant steam dryer damage. The damage was most severe on the 90-degree side of the steam dryer, the side that Was closest to the PORV that had opened. On the 90-degree side, a through-wall crack approximately 90 inches long and up to three inches wide was observed in the top of the outer hood cover plate and the top of the vertical hood plate (refer to Figures B-I and B-2). Three internal braces in the outer hood were detached and one internal brace in the outer hood was severed. The detached braces were found on top of the steam separator. All detached parts were accounted for and retrieved. On the opposite side of the steam dryer (270-degree side), incipient cracking was.observed on the inside of the outer hood cover plate and one vertical brace in the outer hood was cracked. No damage was found. in the cover plates that had been replaced following the first steam dryer failure in 2002.

Three tie bars on top of the steam dryer connecting the steam dryer banks were also cracked. Tie bar cracking has been observed on several other steam dryers (including plants that have not implemented EPU); therefore, tie bar cracking is believed to be unrelated to the other damage noted above.

Root cause of steam dryerfailure Extensive metallurgical and analytical evaluations (e.g., detailed finite element analyses, flow induced vibration analyses, computational fluids dynamics analyses, 1/16'h scale model testing and acoustic circuit analyses) concluded that the root cause of the steam dryer.failure was, high cycle fatigue resultingfrom low frequency pressure loading. There are two potential contributing factors to the failure:

1. Continued operation for approximately I month following the failed cover plate in 2002 which resulted in additional stress loading on the vertical hood plate, and

2. Inadvertent opening of the PORV resulting in a decompression wave, which subjected the steam dryer to two to three times the normal pressure loading. (It is believed that there was incipient cracking in the steam dryer and the PORV event caused the cracks to open up).

The root cause identified in the first steam dryer failure was high cycle fatigue cause by high frequency pressure loading. The low frequency pressure loading was identified as the dominant cause

SIL No. 644 Revision I

• page 12 in this failure. The low frequency pressure loading may have also been a significant contributing factor in the first failure.

CorrectiveA ctions:.

The following repairs and pre-emptive modifications were made to both the 90 and 270-degree sides of the steam dryer:

1.. replaced damaged 1/2 inch outer hood plates with 1 inch plates

2. removed the internal brackets that attached the internal braces to the outer hood

3. added gussets at the outer vertical hood plate and cover plate junction

4. added stiffeners to the vertical welds and horizontal welds on the outer hood The combined effect of these modifications was to increase the natural frequency of the outer hood, reduce the maximum stress by at least a factor of two, and reduce the pressure loading by~reducing the magnitude of vortices in the steam flow near the MSLs.

Following the steam dryer modifications, the unit was returned to service on June 29, 2003.

SIL No. 644 Revision I

• page 13 Figure B-I: Location of the 2003 Outer Hood Failure

SIL No.,644 Revision I

• page.14 SIK o 44Rvso 1.ae1 I .

Figure B-2: Steam Dryer Damage 90 Degree Side

SIL No. 644 Revision 1 - page 15 Appendix C Inspection Guidelines Overview The steam dryers have been divided into four broad types with fourteen sub-groups: BWR/2 -design, square hood design, slanted hood design and the curved hood design. The focus of the inspections for each dryer type is divided into two categories. The first category is directed at the outer surfaces of the dryer that are subject to fluctuating pressure loads during normal operation and arepotentially susceptible to fatigue cracking. The second category is directed at the cracking that has been found in the drain channels and in inner bank end plates. These latter locations are not. associated with any near term risk of.loose part generation. They have often been associated with IGSCC cracking in the heat-affected-zones of stainless steel welds.

Inspection Techniques Based on the current experience in inspecting the dryer components, VT- I is the recommended technique to be employed for the inspections. VT-I resolution, distance, andangle of view requirements should be maintained to the extent practical. In instances where component geometry or remote visual examination equipment limitations preclude the ability to maintain the VT-I requirements over the entire length ofthe different weld seams, "best effort" examinations should be performed. In that cracking will be expected to have measurable length (several inches), field experience has confirmed that "best effort" approaches are sufficient to find the cracking that is present.

Steam Dryer Integrity Inspection Recommendations The recommendations are divided into three categories: BWR/2 and square hood taken together, slanted hood and curved hood steam dryers. The inspection recommendations for each type of dryer will be detailed using schematics of the outer dryer structure. *Thekey weld seams that must be inspected are outlined in red or green. 'High stress locations associated with structural integrity are outlined in red. Locations associated with field dryer cracking experience are outlined in green.

Typical horizontal and vertical welds are shown thereby providing guidance for establishing a plant specific inspection plan. The weld numbering approach shown in the figures is only given as an example. Due to the many welds and size differences, each plant. should employ their own weld numbering system. If an indication is detected, care should be exercised when inspecting the symmetrical locations on the dryer. If an indication is detected on the external surface of a plate or weld, consideration should be given to inspecting the location from the inside of the dryer in order to determine if the indication is through-wall.

SquareHood Design: applicableto B WR/2 plants and B WR/3 plants Several square hood dryers were built with interior brackets and diagonal braces. These stru ctures produce stress concentration locations, which have been found to aid in the initiation of fatigue cracking. These brackets exist in both the outer and the inner dryer banks. The recommended inspections follow.

Steam Dryer Bank Inspections Figure C-I provides the overview of the square dryer design. These dryers will require both an external and internal inspection. All dryers are symmetrical from this perspective. Outlined in red

SIL No. 644 Revision 1

• page 16 are the key weld seams that must be inspected. These welds, both horizontal and vertical outline the outer dryer bank. These locations considered as high stress locations. Figure C-2 displays a cross-section of the BWR/2 steam dryer with the outer bank peripheral welds highlighted. This configuration has no lower cover plate.. However, the external locations that match those shown in Figure C-I need to be inspected in a similar fashion to the other square hood dryers. Figures C-3 and C-4 provide the details of the weld seams as viewed from the dryer bank interior.. As shown in Figure C-3, the outer bank welds. need to be inspected from both the dryer exterior and the dryer interior. In addition, for the dryers where there are interior brackets that were present in the original design and are still present, the interior inspection must be conducted of the weld region where the bracket is joined to the hood vertical and top plates. *FigureC-3 shows these locations for the outer banks hoods. Figure C-4 shows the brackets for the inner hood. In addition, Figure C-5 provides a cross section of the bracket-diagonal brace substructure. The intersection locations between the. bracket and the top and outer hood are also outlined in red in these figures. In that the concern is primarily fatigue cracking, several inches of base material adjacent to welds should be examined as well as any obvious discontinuity; e.g., the exterior base material should be examined in the general area where there is an internal weld.. This inspection examination region includes the heat-affected-zone and will therefore detect any IGSCC cracking. This figure also shows locations in green that exhibited cracking in the field. The region of inspection should be the same.

Tie Bar Inspections In addition to the outer bank and interior bracket locations, tie bars also require inspection. Figure C-6 provides a schematic of the tie bars. These are located between each set of dryer banks.

.Inspections Based on Field Experience.

The other locations of interest are primarily associated with IGSCC in drain channels (shown for information in Figures C-7 and G-8). These components will be part of the. internal examination.

While these indications have been historically associated with BWR/4 through BWR/6 plants (SIL No. 474 "Steam Dryer Drain Channel Cracking" issued October 26, 1988), recent findings indicate that cracking can occur in these locations in square hood dryers. The additional weld seams associated with the outer side of the next set of inner banks should also be inspected in that this represents a steam path through the dryer. These areas are shown in green in Figure C-1. Cracking has been detected in these end panels in later design dryers. Finally, cracking at the steam dams as indicated in green in Figure C-6 has occurred in one BWR/4. These locations .need to be included in the inspection plan for all of these plants. Finally, bank inner surface welds have cracked in the BWR/2. These locations, shown in Figure C-2 in green, also need to be inspected.

Slanted HoodDesign: applicableto B WR/4 plants The slanted hood steam dryers fall into three categories for which the primary difference is diameter and the number of banks. These dryers use 2 or.3 stiffener plates to strengthen each dryer bank. All inspections are on the external surface of the dryer. However, if an indication is detected on the external surface of a plate or weld, consideration should be given to inspecting the location from the inside of the dryer in order to determine if the indication is through-wall. The recommended inspections follow.

Steam Dryer Bank Inspections.

Figure C-9 provides the overview of the slanted dryer design. All dryers are symmetrical from this perspective. Outlined in red are the key weld seams that must be inspected from the external surface.

These welds, both horizontaland vertical outline the outer dryer bank as well as the cover plate

SIL No. 644 Revision 1

• page 17 between the outer hood vertical plate and the support ring. Additional red lines represent the outside projected location where the stiffener plates are welded to the outer hoodvertical plate. These locations are considered as high stress locations. The man-way welds (on one side) are also shown as locations requiring inspection.

Tie Bar Inspections In addition to the outer bank and interior.bracket locations, tie bars also require inspection. Figure C-10 provides a schematic of the tie bar locations joining the tops of each set of banks. The primary concern is the presence of fatigue cracking through the bar base material cross-section at axial location where the tie bar is attached to the bank.

Inspections Based on FieldExperience Cracking has been, detected in these end panels in later design dryers. Therefore, these additional weld seams associated with the outer side of the inner banks should also be inspected in that this represents a steam path through the dryer. These areas are shown in green in Figure C-9. Cracking has been observed in these locations in dryers of this design.' The other locations of interest are primarily associated with IGSCC in drain channels (refer to SIL No. 474 "Steam Dryer Drain Channel Cracking" issued October 26, 1988), support ring, and lifting rod attachments.

CurvedHood Design: applicableto B WR/4-B WR/6 andAB WR plants The curved hood steam dryers fall into five categories for which the primary differences are diameter and inner bank hood thickness. Similar to the slanted hood dryers, these dryers also have 2 or 3 interior stiffener plates to strengthen each dryer bank. All inspections are on the external surface of the dryer. However, if an indication is detected on the external surface of a plate or weld, consideration should be given to inspecting the location from the inside of the dryer in order to determine if the indication' is through-wall. The recommended inspections follow.

Steam Dryer Bank Inspections Figure C-I 1 provides the overview of the curved hood dryer design. All dryers are symmetrical from this perspective. Outlined in red are the key weld seams that must be inspected from the external surface. These welds, both horizontal and vertical outline the outer dryer bankas well as the cover plate between the outer hood vertical plate and the support ring. Additional red lines represent the outside projected location where the stiffener plates are welded to the outer hood vertical plate.

Inspection locations also include outer plenum end plates and inner hood vertical weld seams for BWR/4 and BWR/5 plants with 1/8 inch thick hood plates on the inner banks. The location shown is.

the region where these thinner hood plates are attached to the stiffeners.'All of these locations are considered as relative high stress locations. The man-way welds (on one side) are,also shown as locations requiring inspection.

Tie Bar Inspections In addition to the outer bank and interior bracket locations, tie bars also require inspection. Figure C-I I provides a schematic of the tie bar locations joining the tops of each set of banks. in that the attachment of the tie bars may have employed high heat input welds, the inspection should also include the entire welded region to assess the presence of IGSCC on the bank top plate. This region is adjacent to the region shown in red around the end of the inner bank tie bars.

SIL No. 644 Revision I

• page 18 Inspections Based on Field Experience Cracking has been detected in the end panels in later design dryers. Therefore, these additional. weld seams associated with the outer side of the inner banks should also be inspected in that this represents a steam path through the dryer. These areas are shown in green in Figure C-I 1. Cracking has been observed in these locations in dryers of this design. The other locations of interest are primarily associated with IGSCC in drain channels (refer to SIL No. 474 "Steam Dryer Drain Channel Cracking" issued October 26, 1988) and lifting rod attachments.

SIL No. 644 Revision 1 page 19 0.

...*Vl 90

• V12900 Vt 1 90, V10 90 1800 v8 90.

140'!

V7 90*

V9 90*

l *V190*

H2 H1 900 VUv- 040° \-V5 9C Figure C-1: Inspections: Outer Dryer Hood and Cover Plate (Square Hood Dryer)

SIL No. 644 Revision I page 20 Figure C-2: Cross-Section of BWR/2 Steam Dryer

SIL No. 644 Revision I

• page 21 Vane To End Panel

• 0.

Figure C-3: Weld layout for interior of outer banks (Square Hood DIyer)

The.brackets shown only exist in those plants where they were part of the original design and were not removed as part of dryer modifications.

SIL No. 644 Revision I - page 22 H_-PL4 H_-PL3 H_-PL2 H--PL1 00 1800 H_-PL# = Plate (Bank B, C, D or E) (Ex. HB-PL1)

Internal View - View Is Looking Away From Vane Assembly Figure C-4: Weld Rollout - Inner banks with internal brackets (Square Hood Dryer)

The brackets shown only exist in those plants where they were part of the original design and were not removed as part of dryer modifications.

SIL No. 644 Revision I -.page 23 Vertical Brace Upper Exam Area Dryer Vane Lower Exam Area Bank Trough Figure C-5: Dryer Brace Detail (Square Hood Dryer)

SIL No. 644 Revision I

• page 24 TB-01 0

TB-03 TB-06 __ _ _ _ _ _ _ _ _ _ _ _

270" Figure C-6: Inspection Locations: Tie Bars and Steam Dam Inspections (Square Hood Dryer)

SIL No. 644 Revision 1 - page 25 18 Figure C-7: Drain Channel Locations (Square Hood Dryer)

SIL No. 644 Revision I -page 26 00 41-900> A K\ . 1A20A DC-C-180 -' -DC-D_180 View (Square Dryer Drain Channel, Guide channels and Guide Rod - Bottom Figure C-8:

Hood Dryer)

SIL No. 644 Revision 1 page 27 DC - Drain Channel 6

R1

-V1 5 DC-Vl0-'

Figure C-9: Inspection Locations (Slanted Hood Dryer)

SIL No. 644 Revision 1 *page 28 90" TB-06 -

-0*

TB-07 --

TB-03 TB-##: Tie Bar No. 270:

Figure C-1O: Tie Bar Locations (Slanted Hood Dryers)

(

SIL No. 644 Revision I

• page 29

-I DC-V5 Figure C-I 1: Inspection Locations (Curved Hood Dryer)

SIL No. 644 Revision I

• page 30 Appendix'D Monitoring Guidelines Applicability In general, it is good practice to have access to as much performance data as practicable in order to make informed operational decisions. Therefore, GE recommends that all BWRs implement the moisture carryover and operational response guidance described here. However, plants that have sufficient baseline data and operating experience may elect to consider aless stringent monitoring program.

Background

A moisture carryover greater than 0.1% at the licensed power level is an indication of potential steam dryer damage, unless a higher threshold is established. A higher threshold may be warranted for a BWR with an unmodified square dryer hood(i.e., no addition of perforated plates) and/or operating with MELLLA+ at off-rated core flow.

If plants are reporting measured moisture carryover values of "less than" a value because of inability to measure Na-24 in the condensed steam sample and the "less than" value is greater than 0.025%,

then the moisture carryover measurement process should be modified to reduce the minimum detectable threshold (preferably such that "less than" values are never reported). Without quantitative data, the plant staff will be unable to develop operational recommendations based on statistically valid moisture carryover and other plant data.

BWR moisture carryover may be impacted by: (1) reactor power level, (2) core flow and power distributions, (3) core inlet subcooling (which is related to final Feedwater temperature), and (4) reactor Water level.

Moisture carryover is very sensitive to power level. Therefore, data should be collected during steady state operations at the highest possible power levels.

Moisture carryover has increasedin cases where steam flow is increased towards the center of the core.

Moisture carryover has increased in cases where core inlet sub-cooling is decreased (i.e., final Feedwater temperature is increased).

Moisture carryover has increased in cases where reactor water level is increased (due to degraded separator performance).

Note that the standard deviation of moisture carryover measurements is not expected to change significantly following power distribution changes. However, if a significant condenser tube leak occurs, then the standard deviation of moisture carryover measurements may change significantly due to the resulting increased Na-24 concentrations.

.Plants are recommended to accurately determine the flow distribution between individual steam lines.

If significant steam dryer damage occurs, steam line flow distribution changes may result.

It may be helpful to have pressure data at each main steam flow element (venturi) to better understand the pressure drops and possible pressure changes due to moisture content changes in the steam line flow. This pressure data would have been beneficial at Quad Cities to help identify the flow blockage

SIL No. 644.Revision I

• page 31 upstream of the flow element following significant steam dryer damage. Note that flow element performance calculations are based on the RPV steam dome pressure.

An increased feed-to-steam mismatch (i.e., total Feedwater flow pLus CRD flow minus total steam flow, with reactor water level constant) may validate an increase in moisture carryover. Plant application has confirmed this correlation exists when the initial moisture carryover value is low

(-0.01%), however the correlation showed significant scatter at higher initial moisture carryover values (0.04% to 0.10%).

Baseline Data NOTE Data should be collected during steady state operations at the highest possible power levels..

Moisture Carryover Measure moisture carryover daily to obtain at least five (5) measurements.

Statistically evaluate the moisture carryover data (e.g., determine the mean and standard deviation for the data) to determine if there is a significant increasing trend. Qualitatively. review the data to ascertain if there is a significant increasing trend. If there is an increasing trend in moisture carryover, review the changes in plant operational parameters to determine if there is an operational basis for the trend.

If an unexplained increasing trend is evident, then collect additional moisture carryover data with consideration for increasing the measurement frequency (e.g., from "once per day" to "once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />").-

If an unexplained increasing trend is not evident, then begin collecting periodic data for moisture carryover.

Plant Operational Parameters NOTE Most plant operational data is available from the process computer, which can normally be input into an Excel spread sheet for evaluation and storage.

The following parameters should be measured under the same (or similar) plant conditions that existed during collection.of moisture carryover baseline data:

Reactor power (MWt)

Core flow (Mlb/hr)

Core inlet sub-cooling (deg F)

Reactor water level, average of at least 1000 data points over a one to three hour time period.

Individual main steam line flows (Mlb/hr), average of at least 1000 data points over a one to three hour time period. Include pressure data at each MSL flow element (venturi), if available.

SIL No. 644 Revision I - page 32

'total Feedwater flow (Mlb/hr), average of at least 1000 data points over a one to three hour time period.

CRD flow (Mlb/hr)

Periodic Data and Operational Response NOTE Data should be collected during steady state operations at the highest possible power levels.

If a moisture carryover measurement is suspect (e.g., less than "mean minus 2-sigma"), then repeat the moisture carryover measurement to verify Sampling and analysis were performed correctly.

Consider eliminating data shown to be incorrect/invalid.

Moisture carryover should be monitored weekly.

Statistically evaluate the moisture, carryover data and qualitatively determine if there is a significant increasing trend that cannot be explained by changes in plant operational parameters.

If an unexplained increasing trend is evident, then collect additional moisture carryover data with consideration for increasing the measurement frequency (e.g., from "once per week" to "once per day").

If the latest moisture carryover measurement is greater than "mean plus 2-sigma" and this increase cannot be explained by changes in plant operational parameters, then obtain a complete set of data for the plant operational parameters (identified above). Compare the current plant operational data with the baseline data to explain the increased moisture carryover (i.e., is there steam dryer damage or not).

If an increasein moisture carryover occurs immediately f6llOwing a rod swap, additional moisture carryover data should be obtained, to assure that an increasing trend does not exist. Note that occurrence of steam dryer damage immediately following a rod swap would be highly unlikely.

If the increasing trend of moisture carryover cannot be explained by evaluation of the plant operational data, then initiate plant-specific contingency plans for potential steam dryer damage.

If the evaluationof plant data confirms that significant steam dryer damage has most likely occurred, then initiate a plant shutdown.

If there are no Statistically significant changes in moisture carryover for an operating cycle, then decreasing the moisture carryover measurement frequency (e.g., from "once per week" to "once per month") may be considered, provided the highest operating power level is not significantly increased.

NEC-JH_56 UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, D.C. 20555 January 9, 2004 NRC INFORMATION NOTICE 2002-26, SUPPLEMENT 2: ADDITIONAL FLOW-INDUCED VIBRATION FAILURES AFTER A RECENT POWER UPRATE Addressees All holders of an operating license or a construction permit for nuclear power reactors, except those that have permanently ceased operations and have certified that fuel has been permanently removed from the reactor.

Purpose The U.S. Nuclear Regulatory Commission (NRC) is issuing this supplement to a previously issued information notice (IN) to alert addressees to the failure of the steam dryer and other plant components at Quad Cities Nuclear Power Station, Unit 1 (QC-1), a boiling water reactor (BWR), during operations following a power uprate. The NRC expects that the recipients will review the information for applicability to their facilities and consider actions, as appropriate, to avoid similar problems. However, suggestions contained in this information notice are not NRC requirements. Therefore, no specific action or written response is required.

Description of Circumstances As discussed in IN 2002-26, "Failure of Steam Dryer Cover Plate After a Recent Power Uprate" (ML022530291), a cover plate on the outside of the steam dryer at Quad Cities Nuclear Power Station, Unit 2 (QC-2), broke loose in June 2002 and caused pieces of the dryer to be swept down the main steamline. The failure followed completion of a refueling outage in March 2002 and subsequent implementation of an extended power uprate (EPU) from 2511 MWt to 2957 MWt (17.8% increase). Before the unit was shut down in 2002, steam dryer degradation was indicated by an increase in moisture carryover and minor perturbations in reactor pressure, water level, and steam flow. The licensee evaluated the cause of the steam dryer cover plate failure and determined that the failure of the plate was due to high-cycle fatigue. The licensee recovered all loose dryer pieces and did not identify any additional damage other than minor scratches and gouges to the main steamline. Prior to returning the unit to service, the licensee modified the steam dryer by installing thicker cover plates with higher strength welds, and implemented enhanced monitoring of steam moisture content, reactor steam dome pressure, main steamline flow rates, and reactor water level.

ML040080392

IN 2002-26, Sup 2 Page 2 of 4 The second failure of the steam dryer in May 2003 at QC-2 was discussed in IN 2002-26, Supplement 1, "Additional Failure of Steam Dryer After a Recent Power Uprate" (ML031980434). In that case, the licensee again noted increasing moisture carryover in late May 2003; however, there were no discernible changes in other reactor parameters. On May 28, 2003, the licensee reduced power on QC-2 to the pre-EPU 100% power level. Moisture carryover levels remained above normal, and on June 11, 2003, the licensee shut down QC-2 to inspect the dryer. Inspection of the dryer revealed (1) through-wall cracks (about 90 inches long) in the vertical and horizontal portions of the outer bank hood, 90-degree side, (2) one vertical and two diagonal internal braces detached from the outer bank hood, 90-degree side, (3) one severed vertical internal brace on the outer bank hood, 270-degree side, and (4) three cracked tie bars on top of the dryer. The licensee believes the most probable cause of the failure of the steam dryer in QC-2 is low-frequency, high-cycle fatigue driven'by flow-induced vibrations associated with the higher steam flows present during EPU operating conditions.

In late October 2003 at QC-1, the licensee observed changes in main steamline flows, steamline pressure drop, and increasing moisture carryover measurements. The symptoms observed were consistent with previous events at QC-2 that resulted in the discovery of damage to the steam dryer. The licensee subsequently reduced the power level of QC-1 to pre-EPU conditions. After power was reduced, the moisture carryover was lower than before the power reduction, but higher than the anticipated level. On November 12, the licensee shut down QC-1 to inspect the steam dryer and identified significant damage to several areas. For example, an identified crack was determined to have initiated at the top corner portion of the steam dryer hood and then extended horizontally toward the center of the hood and downward into the vertical section of the hood. The crack terminated in the vertical section where a portion of the dryer was missing. This missing piece of the steam dryer outer bank hood is approximately 6.5 inches (16.5 cm) by 9.0 inches (22.9 cm) and 0.5 inches (1.3 cm) thick. The licensee believes that a piece or pieces the size of this opening or smaller broke off due to fatigue cracking. The licensee performed an extensive but unsuccessful search for the lost part or parts. However, the licensee did identify impact marks on the impeller of the 1 B recirculation pump that suggested that the missing part or parts passed through the pump. The licensee concluded that the missing part or parts migrated to the bottom head region of the reactor vessel. In addition to damage to the steam dryer at QC-1, the licensee identified significant flow-induced vibration damage to main steam line tieback supports and a main steam electromatic relief valve (including its attached drain line, actuator, and support), as well as loose clamps on the main steam line supports. Before restarting QC-1 on November 29, the licensee repaired the steam dryer and other damaged plant components identified during its inspections. With respect to the missing steam dryer metal plate, the licensee performed an operability evaluation for continued operation with the missing part or parts and will decide, prior to the next refueling outage, whether to continue efforts to locate and retrieve the missing dryer material.

IN 2002-26, Sup 2 Page 3 of 4 Discussion When operating above the original licensed thermal power (OLTP) level, BWR plants can experience a significant increase in the velocity of the steam generated from feedwater in the reactor core and directed through piping to the plant turbine generator. This increased steam velocity could damage plant components through flow-induced vibration. While major safety-related components undergo detailed review to demonstrate their capability to perform the applicable safety functions, nonsafety-related components and safety-related subcomponents have received less attention by the licensee and the NRC during preparation for nuclear power plant operation above the OLTP level.

Although performing a nonsafety-related function, the steam dryer in a BWR plant must maintain its structural integrity to avoid loose dryer parts from entering the reactor vessel or steam lines and adversely affecting plant operation. Industry representatives say that cracking occurred in steam dryers during the early operational phase of some BWR plants. The steam dryer failures at Quad Cities while operating at EPU conditions have led the BWR Owners Group (BWROG) to ask its BWR Vessel and Internals Project (BWRVIP) to develop inspection and evaluation guidelines for BWR steam dryers. In addition, General Electric (GE) Nuclear Energy issued Service Information Letter (SIL) 644, "BWR/3 steam dryer failure," on August 21, 2002, and Supplement 1 to SIL 644 on September 5, 2003, to provide monitoring and inspection recommendations for BWR plants that are operating, or plan to operate, at power levels greater than the OLTP.

In addition to the BWR steam dryers, flow-induced vibration during nuclear power plant operation above the OLTP level can potentially damage other plant components.' For example, the QC-1 licensee identified significant flow-induced vibration damage to a main steam electromatic relief valve (including its attached drain line, actuator, and support), as well as main steam line support clamps and tieback supports. Therefore, information obtained from the review of the flow-induced vibration damage at QC-1 might also be applicable to other BWR plants with different steam dryer designs and to pressurized water reactor (PWR) plants operating at conditions above their OLTP level. The significance of the lessons learned is increased because operation of a nuclear power plant under conditions above the OLTP level might place additional reliance on the capability of plant equipment, such as relief valves or seismic restraints, to perform their intended functions as a result of higher reactor power levels and steam and feedwater flow rates.

The NRC staff is reviewing plant-specific and industry-wide activities to address the potential for flow-induced vibration damage to steam dryers and other plant components in BWR plants operating or planning to operate at conditions above the OLTP level. Although it is very unlikely that loose parts would adversely affect the safe shutdown of a plant, it is important to understand the extent of damage that might be caused by steam dryer failures and to identify the lessons learned from recent steam dryer failures for application to steam dryers at other BWR plants. It is also important to address the potential for similar failures in other plant components in BWR or PWR plants operating or planning to operate at conditions above the OLTP level.

IN 2002-26, Sup 2 Page 4 of 4 Licensees should be alert to the possibility of unanticipated effects from increasing flow, power, or differential pressure associated with a major modification such as a power uprate. This information notice requires no specific action or written response. If you have any questions about the information in this notice, please contact one of the technical contacts listed below or the appropriate Office of Nuclear Reactor Regulation (NRR) project manager.

IRA!

William D. Beckner, Chief Reactor Operations Branch Division of Inspection Program Management Office of Nuclear Reactor Regulation Technical Contacts: Karla Stoedter, Region III Jack Foster, NRR (309) 654-2227 (301) 415-3647 E-mail: kkb(anrc.gov E-mail: Owf(anrc.qov Larry Rossbach, NRR Thomas G. Scarbrough, NRR (301) 415-2863 (301) 415-2794 E-mail: Iwranrc.gov E-mail: tqs(anrc.qov

Attachment:

List of Recently Issued NRC Information Notices

Attachment IN 2002-26, Sup 2 Page 1 of 1 LIST OF RECENTLY ISSUED NRC INFORMATION NOTICES Information Date of Notice No. Subject Issuance Issued to 2003-11, Sup 1 Leakage Found on Bottom- 01/08/2004 All holders of operating licenses Mounted Instrumentation or construction permits for nuclear Nozzles power reactors, except those that have permanently ceased operations and have certified that fuel has been permanently removed from the reactor.

2003-22 Heightened Awareness for 12/09/2003 All medical licensees and NRC Patients Containing Detectable Master Materials License medical Amounts of Radiation from use permittees.

Medical Administrations 2003-21 High-Dose-Rate-Remote- 11/24/2003 All medical licensees.

Afterloader Equipment Failure 2003-20 Derating Whiting Cranes 10/22/2003 All holders of operating licenses Purchased Before 1980 for nuclear power reactors, except those who have permanently ceased operations and have certified that fuel has been permanently removed from the reactor vessel; applicable decommissioning reactors, fuel facilities, and independent spent fuel storage installations.

Note: NRC generic communications may be received in electronic format shortly after they are issued by subscribing to the NRC listserver as follows:

To subscribe send an e-mail to <listproc(anrc.qov >, no subject, and the following command in the message portion:

subscribe gc-nrr firstname lastname OL = Operating License CP = Construction Permit

__________________________NEC-JH_57 NE7Page 1

,Rick Ennis - Fwd: VY Steam Dyer.Crack Info From: Rick Ennis M4t-'A '

To: ,A-tlan Wang; Allan Barker; Allen Howe; Anthony McMurtray;. Brian Sheron; Cheng-lh Wu; Christopher Grimes; David Terao; Diane Screnci; Donna Skay; Eric Leeds; Gene Imbro; James Clifford; Jim Dyer; John Craig; John Jolicoeur; Kamal Manoly; Neil Sheehan; Richard Barrett; Richard Borchardt; Scott Burnell; Tae Kim; Terrence Reis; Thomas Scarbrough; William Beckner; William Ruland Date: 4/16/04 1:31PM

Subject:

Fwd: VY Steam Dryer Crack Info Attached is a little more detail on the steam dryer cracking at Vermont Yankee. -

CC: Cliff Anderson; David Pelton

)

IC:\TEMP\GWIOOOO1 *TMP Pcei 11 Pacie Mail Envelope Properties (40801878.B4F:15: 20516)

Subject:

Fwd: VY Steam Dryer Crack Info V" Creation Date: 4/16/04 1:31PM From: Rick Ennis Created By: RXE@nrc.gov Recipients Action Date & Time kpl-po.KPDO Delivered 04/16104 01:3 1PM CJA CC (Cliff Anderson) Opened 04/16/04 01:3 1PM DLP1 CC (David Pelton) Opened 04/19/04 07:13AM DPS (Diane Screnci) Opened 04/16/04 01:53PM NAS (Neil Sheehan) Opened 04/16104 01:43PM owfl-po.,OWFNDO Delivered 04/16/04 01:31PM SRB3 (Scott Burnell) Opened 04/16/04 01:32PM owf2_po.OWFN_DO ' Delivered 04/1.6/04 01:31PM ACM2 (Anthony McMurtray) Opened 04/16/04 01:58PM CIWI (Cheng-lh Wu) Opened 04/17/04 10:14AM DMS6 (Donna Skay) Opened 04/16/04 03:12PM DXT (David Terao) Opened 04/16/04 01:48PM EXI (Gene Imbro) Opened 04/21/04 01:46PM KAM (Kamal Manoly)

RJB3 (Richard Barrett) Opened 04/19/04 07:30AM RWB 1 (Richard Borchardt) Opened 04/16/04 02:20PM TGS (Thomas Scarbrough) Opened 04/16/04 01:34PM TXR (Terrence Reis) owf4.po.OWFN_DO Delivered 04/16/04 01:31PM ABW (Alan Wang) Opened 04/16/04 02:02PM AGH1 (Allen Howe) Opened 04/19/04 07:24AM ARB3 (Allan Barker) Opened 04/16/04 01:3 IPM BWS (Brian Sheron) Opened 04/16/04 04:44PM CIG (Christopher Grimes) Opened 04/16/04 01:35PM EJL (Eric Leeds)

JED2 (Jim Dyer) Opened 04116/04 01:43PM JWC (James Clifford) Opened 04/19/04 09:09AM JWCI (John Craig) Opened 04/16/04 01:32PM TJK3 (Tae Kim) Opened 04116/04 01:40PM WDB (William Beckner) Opened 04/16/04 01:32PM WHR (William Ruland) Opened 04/16/04 01:56PM owf5_po.OWFNDO Delivered 04/16/04 01:31PM C

I C:\TEMP\GW)00001.TMP ..... ... ... . M PPage,2.

JRJ1 (John Jolicoeur) Opened 04/19/04 12:16PM Post Office Delivered Route kpl-po.KPDO 04/16/04 01:3 1PM owfl-po.OWFNDO 04/16/04 01:3 1PM owf2_po.OWFNDO 04/16/04 01:3 1PM owf4_po.OWFNDO 04/16/04 01:31PM owf5_po.OWFNDO 04/16/04 01:31PM Files Size Date & Time Mail MESSAGE 578 04/16/04 01:31PM Options Auto Delete: No Expiration Date: None Notify Recipients: Yes Priority: Standard Reply Requested: No' Return Notification: None Concealed

Subject:

No Security: Standard To Be Delivered: Immediate Status Tracking: Delivered & Opened

I Rick Ennis - Fwd: VY Steam Drver Crack Info Paae'1 I From: Cliff Anderson To: Rick Ennis Date: 4/16/04 12:59PM

Subject:

Fwd: VY Steam Dryer Crack Info fyi J

Rick Ennis - VY Steam Dryer Crack Info Page 1 From: Raymond Lorson To: A. Randolph Blough; Brian Holian; Cliff Anderson; David Pelton; Hubert J. Miller; James Wiggins; Richard Crlenjak; Wayne Lanning Date: 4/16/04 12:11 PM

Subject:

VY Steam Dryer Crack Info FYI:

The attached write-up summarizes what we know about the VY steam dryer cracks to date.

Ray

While performing visual inspections of the reactor vessel steam dryer, Entergy and General Electric personnel identified several indications on both the interior and exterior surfaces of the dryer:

Two external cracks were identified on outer plenum vertical welds (the longest crack was approximately 3 inches in length). The licensee plans to grind out, repair and install additional supports to reinforce these welds;

• Two internal cracks were identified in the drain channel weld. The longest crack was 14 inches in length. These cracks are inaccessible for repair. The licensee (based on input from GE) believes that they can demonstrate that operation with these cracks is acceptable In addition to the cracks noted above, multiple axial indications were identified on the internal surface of the curved end plate of the dryer vane bank. The licensee has not determined whether these indications are cracks or manufacturing anomalies. The licensee (based on input from GE) believes that they can demonstrate that operation with these Indications is acceptable.

The licensee Is considering a press release on this topic and has indicated that the cracks are in low-stress, low-steam flow, areas of the dryer, and not in the areas affected at the EPU plants.

Region I reviewed the licensee's steam dryer Inspection activities during a scheduled, routine IS[

inspection and is continuing to monitor this situation. Similar external weld'cracks were identified and repaired earlier this spring at Nine Mile Unit 2.

NEC-JH 58 July 26, 2004 Mr. Jay K. Thayer Site Vice President Entergy Nuclear Operations, Inc.

Vermont Yankee Nuclear Power Station P.O. Box 0500 185 Old Ferry Road Brattleboro, VT 05302-0500

SUBJECT:

VERMONT YANKEE NUCLEAR POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000271/2004003

Dear Mr. Thayer:

On June 30, 2004, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Vermont Yankee Nuclear Power Station (VY). The enclosed report documents the inspection findings which were discussed on July 12, 2004, with members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one finding of very low safety significance (Green) which was also determined to involve a violation of NRC requirements. Because of the very low safety significance and because the finding was entered into your corrective actions program, the NRC is treating it as a non-cited violation (NCV), consistent with Section VI.A of the NRC's Enforcement Policy. If you contest this non-cited violation, you should provide a response.

within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with

-copies to the Regional Administrator Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Vermont Yankee Nuclear Power Station.

Jay K. Thayer 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely, IRA/

Clifford J. Anderson, Chief Projects Branch 5 Division of Reactor Projects Docket No. 50-271 License No. DPR-28

Enclosure:

Inspection Report 05000271/2004003 w/

Attachment:

Supplemental Information Docket No. 50-271 License No. DPR-28 5

Jay K. Thayer 3 cc w/encl: M. R. Kansler, President, Entergy Nuclear Operations, Inc.

G. J. Taylor, Chief Executive Officer, Entergy Operations J. T. Herron, Senior Vice President and Chief Operating Officer D. L. Pace, Vice President, Engineering B. O'Grady, Vice President, Operations Support J. M. DeVincentis, Manager, Licensing, Vermont Yankee Nuclear Power Station Operating Experience Coordinator - Vermont Yankee Nuclear Power Station J. F. McCann, Director, Nuclear Safety Assurance M. J. Colomb, Director of Oversight, Entergy Nuclear Operations, Inc.

J. M. Fulton, Assistant General Counsel, Entergy Nuclear Operations, Inc.

S. Lousteau, Treasury Department, Entergy Services, Inc.

Administrator, Bureau of Radiological Health, State of New Hampshire Chief, Safety Unit, Office of the Attorney General, Commonwealth of Mass.

D. R. Lewis, Esquire, Shaw, Pittman, Potts & Trowbridge G. D. Bisbee, Esquire, Deputy Attorney General, Environmental Protection Bureau J. Block, Esquire D.-Katz, Citizens Awareness Network (CAN)

M. Daley, New England Coalition on Nuclear Pollution, Inc. (NECNP)

R. Shadis, New England Coalition Staff C. McCombs, Commonwealth of Massachusetts, SLO Designee G. Sachs, President/Staff Person, c/o Stopthesale J. Sniezek, PWR SRC Consultant R. Toole, PWR SRC Consultant J. P. Matteau, Executive Director, Windham Regional-Commission State of New Hampshire, SLO Designee State of Vermont, SLO Designee

Jay K. Thayer A4 Distribution w/encl: H. Miller, RA/J. Wiggins, DRA (1)

C. Anderson, DRP D. Florek, DRP D. Pelton, Senior Resident Inspector C. Miller, RI EDO Coordinator J. Clifford, NRR R. Ennis, PM, NRR D. Skay, Backup PM, NRR Region I Docket Room (with concurrences)

DOCUMENT NAME:C:\ORPCheckout\FileNET\ML042080530.wpd After declaring this document "An Official Agency Record" it will/will not be released to the Public.

To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E"= Copy with attachment/enclosure "N" = No copy OFFICE RI:DRP NAME Pelton/CJA for I RI:DRP Florek/CJA for I RI:DRP Anderson/CJA 1

DATE 07/26/04 07/26/04 07/26/04

/ r OFFICIAL RECORD COPY

U.S. NUCLEAR REGULATORY COMMISSION REGION I Docket No. 50-271 Licensee No. DPR-28 Report No. 05000271/2004003 Licensee: Entergy Nuclear Vermont Yankee, LLC Fadility: Vermont Yankee Nuclear Power Station Location: 320 Governor Hunt Road Vernon, Vermont 05354-9766 Dates: April 1, 2004 - June 30, 2004 Inspectors: David L. PeltonK Senior Resident Inspector Beth E. Sienel, Resident Inspector E. Harold Gray, Senior Reactor Inspector Todd J. Jackson, Senior Project Engineer James D. Noggle, Senior Health Physicist Larry L. Scholl, Senior Reactor Inspector Keith A. Young, Senior Reactor Inspector Amar C. Patel, Reactor Inspector Jennifer A. Bobiak, Reactor Inspector Thomas P. Sicola, Reactor Inspector Approved by: Clifford J. Anderson, Chief Projects Branch 5 Division of Reactor Projects Enclosure

TABLE OF CONTENTS J

SUM MARY O F FINDING S ............................................ ....... iii R EACTO R SA FETY ......................................................... 1 iR01 Adverse W eather ................................................ 1 1 R02 Evaluations of Changes, Tests, or Experiments ........................ 1 1R04 Equipm ent Alignm ents ........... ........................ ........ 2 1R05 Fire Protection ................................................ 3 1 R06 Flood Protection Measures ......................................... 3 1R08 Inservice Inspection .............................................. 4 1Ri1 Licensed Operator Requalification ................................... 5 1R12 Maintenance Effectiveness ...................................... 6 1R13 Maintenance Risk Assessment and Emergent Work Evaluation ............ 6 1R14 Personnel Performance During Non-routine Plant Evolutions .............. 7 1R 15 O perability Evaluations ..... : ..................................... 8 1R16 Operator Workarounds ................ 8 1R17 Permanent Plant Modifications ..................................... .9 1R19 Post Maintenance Testing ........................................ 10 1R20 Refueling and Outage Activities .............................. ....... 10 1R22 Surveillance Testing ...................................... ....... 15 1R23 Tem porary Modifications ......................................... 16 1EP6 Drill Evaluation ............................................... 16 RADIATION SAFETY ..................................................... 17 20S1 Access Control to Radiologically Significant Areas ..................... 17 20S2 ALARA Planning and Controls .................................... 17 O THER ACTIVITIES (OA) ................................................... 18 40A1 Performance Indicator Verification .................................. 18 40A2 Identification and Resolution of Problems ............................. 18 40A3 Event Followup ........  : ....................................... 19 40A5 Other Activities ..................................... .... ...... 20 40 A6 Meetings, including Exit ... ....................................... 20 SUPPLEMENTAL INFORMATION ............................................ A-1 KEY POINTS OF CONTACT ................................................ A-1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ........................... A-1 LIST OF DOCUMENTS REVIEW ED .......................................... A-2 LIST OF ACRONYMS .................................................... A-6 ii Enclosure

SUMMARY

OF FINDINGS IR 05000271/2004003; 04/01/04 - 06/30/04; Vermont Yankee Nuclear Power Station; Refueling and Outage Activities.

This report covered a 13-week period of baseline inspection conducted byresident inspectors.

Additionally, announced inspections were performed by regional inspectors in the areas of occupational radiation protection; evaluations of changes, tests, and experiments; in-service inspections;. and permanent plant modifications. One Green non-cited violation (NCV) was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"

Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings Cornerstone: Barrier Integrity (Green) A self-revealing, non-cited violation (NCV) of 10 CFR 50 Criterion XVI was identified in that Entergy personnel did not develop effective corrective actions to prevent recurrence following a 2001 event wherein control room operators did not verify a suction path existed prior to starting the residual heat removal (RHR) system pump being used to support shutdown cooling (SDC) operations which caused the pump to trip. On April 10, 2004, an identical event occurred and again resulted in a trip of the RHR pump being used to support SDC operations. /

The finding is greater than minor since it is associated with the Fuel Cladding Configuration Control Attribute of the Barrier Integrity Cornerstone and because it affects the associated Cornerstone objective. The inspectors conducted a SDP Phase 1 screening of the finding in accordance with IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process [SDP]." In accordance with the SDP, the inspectors determined that the finding was of very low safety significance (Green) since the RHR pump was restarted within 15. minutes of being tripped and an adequate SDC thermal margin was maintained as demonstrated by a calculated reactor coolant system (RCS) time-to-boil of greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

A contributing cause of this finding is related to the Cross-Cutting area of Problem Identification and Resolution. As stated above, Entergy personnel did not develop effective corrective actions to prevent recurrence following a 2001 event wherein control room operators did not verify a suction path existed prior to starting the RHR system pump being used to support SDC operations which caused the pump to trip. Entergy's corrective actions relied on the operator's skill to verify a suction path was open prior to restarting the RHR pump rather than proceduralize the step. As a result, an identical event occurred in April 2004 again resulting in a trip of the RHR pump being used to support SDC operations. (Section 40A3.1) iii Enclosure

Summary of Findings (cont'd)

B. Licensee Identified Findinqs None.

iv Enclosure

REPORT DETAILS Summary of Plant Status Vermont Yankee Nuclear Power Station entered the inspection period at or near full power.

The reactor was-shutdown on April 3, 2004, in support of planned refueling outage (RFO) 24.

Reactor startup activities began on May 3, 2004, following the completion of RFO 24. The reactor was returned to full power operation on May 8, 2004. On June 18, 2004, an automatic reactor scram occurred as a result of a turbine trip following multiple faults-to-ground on the 22 kilovolt (KV) electrical system. The reactor remained shutdown for the rest of the inspection period.

1. REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity 1 R01 Adverse Weather (71111.01)

a. Inspection Scope (one sample)

The inspectors reviewed measures established by Entergy for the restoration from cold weather operations. The inspectors reviewed Vermont Yankee Operating Procedure (OP) 2196, "Preparations for Cold Weather Operations," Form VYOPF 2196.02, "Cold Weather Restoration Operations Checklist," discussed the completion of items with operations personnel to confirm the items on the checklist had been completed or were appropriately tracked for completion, and independently walked down portions of the plant to verify selected actions td restore from cold weather, operations had been completed appropriately.

b. Findings No findings of significance were identified.

1,R02 Evaluations of Changes, Tests, or Experiments (71111.02)

a. Inspection Scope (eight samples)

The inspectors reviewed the 10 CFR 50.59 safety evaluations or screening evaluations associated with plant modifications being installed during the current refueling outage to support a proposed power uprate. The inspectors assessed the adequacy of the safety evaluations through interviews with the cognizant plant staff and review of supporting documentation to verify the changes were performed in accordance with 10 CFR 50.59 and when required, NRC approval was obtained prior to implementation. The inspectors also reviewed a sample of changes the licensee had evaluated (using a screening process) and determined to be outside of the scope of 10 CFR 50.59, therefore not requiring a full safety evaluation. The inspectors performed this reviewv to determine if Entergy conclusions with respect to 10 CFR 50.59 applicability were appropriate. A

,listing of the modifications for which associated safety evaluations, safety evaluation Enclosure

2 screenings, and other documents were reviewed is provided in the Attachment to this.

report.

b. Findings No findings of significance were identified.

1R04 Equipment Alignments 1.. Complete Equipment Alignment (71111.04S)

a. Inspection Scope (one sample)

The inspectors performed a complete equipment alignment inspection of the accessible portions of the core spray (CS) system. The inspectors walked down the CS system, both inside and outside of the primary containment, and compared actual equipment alignment to approved piping and instrumentation diagrams, operating procedure lineups, the Vermont Yankee updated final safety analysis report (UFSAR), and the Vermont Yankee design basis document (DBD). The inspectors observed valve positions, the availability of power supplies, and the general condition of selected components to verify there were no unidentified deficiencies. The inspectors also confirmed that licensee-identified equipment problems had been entered into the corrective actions program.

b. Findings No findings of significance were identified.

2. Partial Equipment Alignments (71111.04)

a. Inspection Scope (four samples)

• The inspectors performed four partial system walkdowns of risk significant systems to verify system alignment and to identify any discrepancies that would impact system operability. Observed plant conditions were compared with the standby alignment of equipment specified in the licensee's system operating procedures and drawings. The inspectors also observed valve positions, the availability of power supplies, and the general corhdition of selected components to verify there were no obvious deficiencies.

The inspectors verified the alignment of the following systems:

The spent fuel pool (SFP) cooling system while the "A" train of the residual heat removal (RHR) system was unavailable to support shutdown cooling on June 6, 2004; The "B"train of the standby gas treatment (SBGT) system during planned maintenance on the "A" SBGT fan on June 7, 2004; Enclosure N

'N

3 The "A"train of SBGT during planned instrument calibrations on the "B" train of SBGT on June 8; and The emergency diesel generators (EDGs), start-up transformers, the diesel oil storage tank (DOST) following the main transformer fire on June 18, 2004.

b. Findings No findings of significance were identified.

1 R05 Fire Protection (71111.05Q)

a. Inspection Scope (nine samples)

The inspectors identified fire areas important to plant risk based on a review of Entergy's the Vermont Yankee Safe Shutdown Capability Analysis, the Fire Hazards Analysis, and the individual plant evaluation of external events (IPEEE). The inspectors toured plant areas important to safety in order to verify the suitability of Entergy's control of transient combustibles and ignition sources, and the material condition and operational status of fire protection systems, equipment, and barriers. The following fire areas were inspected:

• Reactor building, 252 foot elevation-Si cable trays (CFZ-3/4);

• Reactor building, 252 foot elevation-S2 cable trays (CFZ-3/4);

• Reactor building, 252 foot elevation, North (FZ RB3);

• Reactor building, 252 foot elevation, South (FZ RB4);

• Reactor building, 280 foot elevation, Recirc MG set area (SZ RB-MG);

• Turbine building, all elevations (FA TB);

• Torus room, 213 foot elevation, North (FZ RB1);

• Torus room, 213 foot elevation, South (FZ RB2);

• 345 KV relay house.

b. Findings No findings of significance were identified.

1 R06 Flood Protection Measures (71111.06)

a. Inspection Scope (one sample)

The inspectors reviewed Entergy's established flood protection barriers and procedures for coping with internal flooding in the EDG-rooms including Vermont Yankee Off-Normal Procedure (ON) 3148, "Loss of Service Water"; and ON 3158, "Reactor Building High Area Temperature/Water Level." The inspectors reviewed internal flooding information contained in Entergy's IPEEE, in the UFSAR, and in the Internal Flooding DBD as it related to the EDG rooms. Finally, the inspectors performed walk-downs of flood vulnerable portions of the EDG rooms to ensure equipment and structures needed Enclosure

4 to mitigate an internal flooding event were as described in the IPEEE'and the DBD.

Additionally, the inspectors reviewed condition reports (CRs) related to internal flooding and the EDG rooms to ensure identified problems were properly addressed for resolution.

b. Findings No findings of significance were identified.

1R08 Inservice Inspection (71 111.08G)

a. Inspection Scope (four samples)

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Theý inspectors assessed the inservice inspection (ISI) activities using the criteria specified in the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI.

The inspectors observed selected in-process non-destructive examination (NDE) activities, reviewed documentation and interviewed personnel to verify that the activities were performed in accordance with the ASME Boiler and Pressure Vessel Code Section XI requirements. The sample selection was based on the inspection procedure objectives and risk priority of those components and systems where degradation would result in a significant increase in risk of core damage. The inspectors reviewed a sample of condition reports and quality assurance audit reports to assess the licensee's effectiveness in problem identification and resolution. The specific ISI activities selected for review included:

• Observation of the ultrasonic testing (UT) manual technique, UT procedure, weld overlay calibration test block, and performance of pre and post examination calibration for UT of the CS system N5A'safe-end to nozzle structural weld-overlay;

• Review of the computer based UT procedure and observation of its application for the reactor vessel welds and the eddy current (ET) examination method to quantify clad crack shadowing of volumetric vessel weld examinations and the results for the reactor vessel flange-to-vessel weld;

• Observation of the UT examination of a pre-existing reactor vessel weld indication for verification that the indication was appropriately characterized and had not increased in dimension since the previous examination;

• Review of CS system sparger video-visual examination records;

• Review of the inspection scope expansion and disposition, of two small linear indications on a standby liquid control system socket weld (SL 1-F1 2); and

• Review of the r~eactor vessel internals project (BWRVIP-03 Rev 6) procedure and observation of some of the initial visual examinations.

In response to Entergy's extended power up-rate request and recent industry operating experience, the inspectors observed portions of the steam dryer visual testing (VT) type Enclosure

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5' 1 and'type 3 examinations and reviewed the documented examination reports. The examination reports documented that cracks were identified on both the internal and external surfaces of the, steam dryer. The inspectors reviewed Entergy's corrective actions for these indications to ensure that the actions were appropriate. Specifically, the inspectors reviewed the weld repair activities for the two cracks identified on the external surface of the steam dryer. The inspectors also reviewed the vendor technical reports which justified operation for the next operating cycle at the current maximum licensed power level without repair of the indications identified on internal portions of the steam dryer.

b. Findings No findings of significance were identified.

1Rll Licensed Operator Requalification (71111.11Q)

a. Inspection Scope (one sample)

The inspectors observed simulator examinations for one operating crew to assess the performance of the licensed operators and the ability of Entergy's Training Department staff to evaluate licensed operator performance. Operating crew performance was evaluated during a simulated main steam line break inside the drywell coincident with a loss of normal power. The inspectors evaluated the crew's performance in the areas of:

• Clarity and formality of communications;

• Ability to take timely actions;

• Prioritization, interpretation, and verification of alarms;

• Procedure use;

• Control board manipulations;

• Oversight and direction from supervisors; and

• Group dynamics.

Crew performance in these areas was compared to Entergy management expectations and guidelines as presented in the following documents:

• Vermont Yankee Administrative Procedure (AP) 0151, "Responsibilities and Authorities of Operations Department Personnel";

• AP 0153, "Operations Department Communication and Log Maintenance"; and

• Vermont Yankee Department Procedure (DP) 0166, "Operations Department Standards."

The inspectors verified that the crew completed the critical tasks listed in the associated simulator evaluation guide (SEG). The inspectors also compared simulator configurations with actual control board configurations. For any weaknesses identified, the inspectors observed the licensee evaluators to verify that they also noted the issues to be discussed with the crew.

Enclosure

6

b. Findings No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12Q)

a. Inspection Scope (three samples)

The inspectors performed three issue/problem-oriented inspections of actions taken by Entergy in response to the following issues:

As-found local leakage rate testing (LLRT) failures of the high pressure coolant injection (HPCI) turbine exhaust vacuum breakers; Repeat failures of the "C" residual heat removal service water (RHRSW) system pump motor cooling solenoid valve; and A trend of unavailability associated with the diesel-driven fire pump.

The inspectors reviewed applicable system maintenance rule scoping documents, system health reports, corrective actions taken in response to the equipment problems, maintenance rule functional failure determinations, and applicable a(1) action plans. In addition, the issues were discussed with the responsible engineer.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Evaluation (71111.13)

a. Inspection Scope (seven samples)

The inspectors evaluated on-line and outage risk management for six planned and one emergent maintenance activities. The inspectors reviewed maintenance risk evaluations, work schedules, recent corrective actions, and control room logs to verify that other concurrent or emergent maintenance activities did not significantly increase plant risk. The inspectors also compared these items and activities to requirements listed in Vermont Yankee AP 0125, "Equipment Release"; AP 0172, "Work Schedule Risk Management - Online"; and AP 0173, "Work Schedule Risk Management -

Outage." The inspectors reviewed the following work activities:

Online Risk:

Planned maintenance on the service water (SW) system supply to turbine the building valve SW-19B breaker, resulting in Yellow online risk; Planned maintenance on the "A" train of SBGT; and Emergent work to implement minor modification on average power range monitors (APRMs), resulting in a 1/2/scram condition and "Yellow" online risk.

Enclosure

7 Outage Risk:

Planned realignment and testing of offsite electrical power via the delayed backfeed through the auxiliary and main transformers; Planned maintenance resulting in 345 KV 340 line and "IT" breaker being out of service;

• Portions of planned maintenance on electrical buses 2, 4, and 9; and

• Planned performance of reactor pressure vessel leakage testing; considered by Entergy to be a "high risk evolution."

b. Findings No findings of significance were identified.

1R14 Personnel Performance During Non-routine Plant Evolutions (71111.14)

a. Inspection Scope (two samples)

The inspectors assessed the control room operator performance during the following two non-routine evolutions:

Entry into emergency operating procedure (EOP) 3, "Primary Containment Control," due to average torus temperature exceeding 90 degrees during HPCI system testing on May 26, 2004; and -

Reactor scram following the main transformer fire on June 18, 2004.

Specifically, the adequacy of personnel performance, procedure compliance, and use of the corrective action process were evaluated against the requirements and expectations contained in technical specifications and the following station procedures, as applicable:

• AP 0151, "Responsibilities and Authorities of Operations Department Personnel";

• AP 0153, "Operations Department Communication and Log Maintenance";

• Vermont Yankee DP 0166, "Operations Department Standards;"

• Vermont Yankee OP 105, "Reactor Operations"; and

• OP 2124, "Residual Heat Removal System."

b. Findincs No findings of significance were identified.

1 R15 Operability Evaluations (71111.15)

a. Inspection Scope (five samples)

Enclosure

8 The inspectors reviewed five operability determinations prepared by the licensee. The inspectors evaluated the selected operability determinations against the requirements and guidance contained in NRC Generic Letter 91-18, "Resolution of Degraded and Nonconforming Conditions," as well as procedures AP 0167, "Operability Determinations," and ENN-OP-104, "Operability Determinations." The inspectors verified the adequacy of the following evaluations of degraded or non-conforming conditions:

• Flow noise from the "C" RHR system pump discharge orifice;

• Broken 4 KV breaker driving pawl;

• Missing "clam shell" from the control rod drive housing support system;

) Apparent non-conservative flow-biased scram setpoints; and

• Incomplete NDE for lifting and handling gear.

b. Findings No findings of significance were identified.

1R16 Operator Workarounds (71111.16)

a. Inspection Scope (one sample)

The inspectors reviewed the cumulative effect of operator workarounds on the reliability, availability, and potential mis-operation of systems ýnd the potential to affect the ability of operators to respondto plant transients and events. The inspectors reviewed identified operator burdens, control room deficiencies, disabled or illuminated control room alarms, and component deviations and discussed them with responsible operations personnel to ensure they were appropriately categorized and tracked for resolution. In addition, in-plant and control room tours were performed to identify any workarounds not previously identified in accordance with procure DP 0166, "Operations Department Standards."

b. Findings No findings of significance were identified.

Enclosure

9 1R17 Permanent Plant Modifications

1. Annual Review (71111.17A)

a. Inspection Scope (one sample)

The inspectors performed an annual review of a permanent plant modification involving the installation of an additional main steam safety valve installed during RFO 24. The inspectors reviewed this modification to verify that the design bases, licensing bases, and performance capability of risk significant structures, systems, and components (SSCs) had not been degraded through the modifications. The review evaluated the impact of the modification on power operation at the current licensed power level and potential future operation at an increased power rating. This plant modification was selected for review based on risk insights for the plant and included SSCs associated with the initiating events, mitigating systems and barrier integrity cornerstones. The inspection included a walkdown of the modification, interviews with plant staff, and the review of applicable documents including procedures, Vermont Yankee Design Calculation (VYDC) 2003-013, the modification package, engineering evaluations, drawings, corrective action documents, the UFSAR and Technical Specifications. The inspectors verified that selected attributes were consistent with the current design and licensing bases. These attributes included component safety classification, energy requirements supplied by supporting systems, instrument set-points, and control system interfaces. Design assumptions were reviewed to verify that they were technically appropriate and consistent with the UFSAR. The inspectors verified that selected procedures, calculations and the UFSAR were properly updated with revised design information and operating guidance. The inspectors also verified that the as-built configuration was accurately reflected in the design documentation and that post-modification testing was appropriate.

b. Findings No findings of significance were identified.

2. Biennial Review (71111.17B)

a. Inspection Scope (six samples)

The inspectors performed a biennial review of selected plant modifications that were being installed during RFO 24. The modifications support a proposed power uprate that is currently under review by the Office of Nuclear Reactor Regulation (NRR). The inspectors reviewed the modifications to verify that the design bases, licensing bases, and performance capability of risk significant SSCs had not been degraded through the modifications. The reviews evaluated the impact of the modifications on power operation at the current licensed power level and potential future operation at an increased power rating. Plant modifications were selected for review based on risk insights for the plant and included SSCs associated with the initiating events, mitigating Enclosure

10 systems and barrier integrity cornerstones. The inspection included walkdowns of selected plant systems and components, interviews with plant staff, and the review of applicable documents including procedures, calculations, modification packages, engineering evaluations, drawings, corrective action documents, the UFSAR and Technical Specifications. The inspectors verified that selected attributes were consistent with the current design and licensing bases. These attributes included component safety classification, energy requirements supplied by supporting systems, instrument set-points, and control system interfaces. Design assumptions were reviewed to verify that they were technically appropriate and consistent with the UFSAR.

The inspectors verified that selected procedures, calculations and the UFSAR were properly updated with revised design information and operating guidance. The inspectors also verified that the as-built configuration was accurately reflected in the design documentation and that post-modification testing was appropriate. A listing of documents reviewed is provided in the Attachment to this report.

b. Findings No findings of significance were identified.

1R19 Post Maintenance Testing (71111.19)

a. Inspection Scope (three samples)

The inspectors reviewed completed documentation for three post-maintenance test (PMT) activities to Verify the test data met the required acceptance criteria contained in the licensee's Technical Specifications, UFSAR, and in-service-testing program, and that the PMT was adequate to verify system operability and functional capability following maintenance. The inspectors reviewed the PMTs performed after the following' maintenance activities:

Installation of low feedwater pump suction pressure trip modifications in accordance with minor modification (MM) 2003-015; APRM flow control trip reference card replacement in accordance with MM 2003-028; and Disassembly and repair of HPCI turbine exhaust check valve V23-3 following failed as-found LLRT.

The inspectors verified that systems were properly restored following testing and that discrepancies were appropriately documented in the corrective action process; The inspectors also discussed the PMT results with the responsible engineers.

b. Findings No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20)

Enclosure

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1. Refueling Outage (RFO) 24

a. Inspection Scope (one sample)

The inspectors evaluated the following outage activities to verify that Entergy considered risk when developing outage schedules; that Entergy adhered to administrative risk reduction methodologies for plant configuration control; and to ensure that Entergy adhered to their operating license, Technical Specification requirements, and approved procedures:

Review of the Outage Plan - The inspectors reviewed the RFO 24 shutdown risk assessment to verify, that Entergy addressed the outage's impact on defense-in-depth for the five shutdown critical safety functions; electrical power availability, inventory control, decay heat removal, reactivity control, and containment. Adequate defense-in-depth was verified for each safety function and / or where redundancy was limited or not available, the existence of appropriate planned contingencies, to minimize the overall risk, was verified:'

Consideration of operational experience was also verified. The daily risk up-date, accounting for schedule changes and unplanned activities were also periodically reviewed; Monitoring of Shutdown Activities - The inspectors observed the shutdown of the reactor plant including reactor plant cooldown and transition to shutdown cooling operations. As soon as practical following the shutdown, the inspectors performed walkdowns of the primary containment; Electrical Power - The inspectors reviewed the status and configuration of safety-related buses throughout RFO 24. The inspectors ensured the electrical lineups met the requirements of Technical Specification and the outage risk control plan. The inspectors performed frequent walkdowns of affected portions of the electrical plant including startup transformers, the auxiliary transformer, and the emergency diesel generators; Decay heat removal (DHR) System Monitoring - The inspectors monitored, decay heat removal status on a daily basis. Monitoring included daily reviews of residual heat removal system alignment, reviews of spent fuel pool cooling -

system alignment, and reviews of reactor coolant system (RCS) time-to-boil calculations and results; Inventory Control - The inspectors performed daily RCS inventory control reviews including reviews of available injection systems and flow paths to ensure consistency with the outage risk plan. The inspectors also ensured that operators maintained reactor vessel and/or refueling cavity levels within established ranges; Reactivity Control - The insp~ectors observed reactivity management actions taken by control room operators during refueling evolutions including procedure place keeping, communications with refueling floor personnel, the monitoring of source range nuclear instrumentation, and the monitoring of individual control rod positions; Enclosure

12 Containment Closure - The inspectors performed a torus internal cleanliness walkdown following completion of outage activities., The inspectors performed a primary containment closeout walkdown prior to final containment closure.

Finally, the inspectors ensured secondary containment was maintained as required by Technical Specifications; Refueling Activities - The inspectors observed portions of refueling operations, including fuel handling and accounting in the reactor vessel and spent fuel pool.

The inspectors also performed an independent core reload verification of approximately 34% of the core; and Heatup and Startup Activities - The inspectors observed portions of the heatup and startup of the reactor plant following thecompletion of RF024.

The inspectors also verified that Entergy identified problems related to refueling activities and entered them into their corrective actions program.

b. Findings

Introduction:

A very low safety significance (Green), self-revealing, non-cited violation (NCV) of 10 CFR 50 Criterion XVI was identified in that Entergy personnel did not develop effective corrective actions to prevent recurrence following a 2001 event wherein control room operators did not verify a suction path existed prior to starting a residual heat removal (RHR) system pump being used to support shutdown cooling (SDC) operations which caused the pump to trip. On April 10, 2004, an identical event occurred and again resulted in a trip of the RHR pump being used to support SDC operations.

Description:

On April 10, 2004, control room operators realigned vital alternating current (AC) power from its normal power supply to the backup power supply to support planned maintenance on a vital AC motor generator. The reactor-plant was in the refueling mode of operation at that time. In preparation for the vital AC realignment, operators temporarily secured the RHR system, which was running in the SDC mode of operation.

One of the automatic actions that occurred during the vital AC alignment was the closure of the RHR pump suction valve V1 0-17 from a Group 4 containment isolation signal. Once the realignment of the vital AC power was completed, operators reset the expected partial Group 4 containment isolation signal, but did not recognize that this partial Group 4 containment isolation signal resulted in the closure of RHR system valve V1 0-17, isolating the suction path used for RHR system support of SDC. Operators subsequently attempted to reinitiate the RHR system in accordance with Vermont Yankee Operating Procedure (OP) 2124, "Residual Heat Removal System," Section J, "Short Term Shutdown Cooling Shutdown and Startup." When the "B" RHR pump was started, the pump's breaker immediately tripped open due to a designed electrical interlock requiring valve V1 0-17 to be open to provide a suction path for the RHR system. Operators investigated the cause of the pump breaker trip, identified that no suction path existed since valve V1 0-17 had closed, re-opened valve V10-17, and successfully restarted the "B" RHR pump within 15 minutes of the breaker trip.

Enclosure

13 SDC thermal margin was maintained throughout this event via continued operation of the spent fuel pool cooling system along with a calculated RCS time-to-boil value of greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

In the apparent cause report for this event, Entergy identified that a nearly identical event had occurred during a refueling outage in May 2001. At that time, operators had performed a planned realignment of the vital AC power but did not recognize that valve V1 0-17 had closed which resulted in a trip of the "C" RHR pump breaker when operators attempted to reinitiate the RHR system. Entergy documented this previous event in event report (ER) 2001-01228. Corrective actions assigned at that time included discussions at shift supervisor meetings and the counseling of involved operators. In the apparent cause report, Entergy also concluded that the corrective actions taken to address the May 2001 event were insufficient to have prevented recurrence of the nearly identical April 2004 event. Specifically, no corrective actions were assigned to address the fact that OP 2124, Section J, did not specifically require operators to verify an adequate RHR system flow path to and from the reactor existed prior to reinitiating system operation.

Analysis: The performance deficiency associated with this finding is that Entergy personnel did not assign effective corrective actions to prevent recurrence as required by VY Administrative Procedure 0009 following a May 2001 trip of the "C" RHR pump which occurred when operations did not recognize that RHR system valve V10-17 had gone closed during a realignment of vital AC power. As a result, a similar event occurred in April of 2004 involving a trip of the "B" RHR pump resulting from operators again failing to recognize the closure of valve VI 0-17 during a realignment of vital AC power. The finding is greater than minor since it is associated with the Fuel Cladding Configuration Control Attribute of the Barrier Integrity Cornerstone and because it affects the associated Cornerstone objective. Specifically, the April 2004 trip of the "B" RHR pump, used to support SDC operations, reduced the assurance that the fuel cladding would protect the public from radio nuclide releases caused by accidents or events. The inspectors conducted a SDP Phase 1 screening of the finding in accordance with IMC 0609, Appendix G, "Shutdown Operations Significance Determination Process [SDP]." The inspectors determined that Entergy did not meet Item I.C. of Table 1, "BWR [Boiling Water Reactor] Refueling Operation with RCS Level

> 23"' since the finding resulted in Entergy not having at least one RHR loop operating to support SDC.> However, the inspectors also determined that the finding did not degrade Entergy's ability to recover SDC since the "B" RHR pump was restarted within 15 minutes of being tripped and an adequate thermal margin was maintained via a calculated RCS time-to-boil of greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Therefore, in accordance with IMC 0609, Appendix G, the finding was of very low safety significance (Green).

A contributing cause of this finding is related to the Cross-Cutting area of Problem Identification and Resolution. As stated above, Entergy personnel did not develop effective corrective actions to prevent recurrence following a 2001 event wherein control room operators did not verify a suction path existed prior to starting the RHR system pump being used to support SDC operations which caused the pump to trip. Entergy's corrective actions relied on the operator's skill to verify a suction path was open prior to Enclosure

14 restarting the RHR pump rather than proceduralize the step. As a result, an identical event occurred in April 2004 again resulting in a trip of the RHR pump being used to support SDC operations.

Enforcement:

10 CFR 50, Appendix B, Criterion XVI states, in part, that measures shall be establish'ed to assure that conditions adverse to quality are promptly identified and corrected.

Vermont Yankee AP 0009, "Event Reports," Revision 12, describes Entergy's requirements for the identification and correction of conditions adverse to quality including determining the cause(s) of the event and assigning corrective actions that prevent recurrence. Contrary to the above, in May 2001, Entergy did not assign effective corrective actions that prevent recurrence following a May 2001 trip of the "C" RHR pump which occurred when operators did not recognize that RHR system valve V1 0-17 had closed due to an expected partial Group 4 containment isolation during the realignment of vital AC power. As a result, a similar event occurred in April of 2004 involving the trip of the "B" RHR pump resulting from operators again failing to recognize the closure of valve V10-17 during a realignment of vital AC power. Because the finding is of very low safety significance and has been entered into the licensee's Corrective Actions Program (CR 2004-01005), this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 0500271/2004003-01, Ineffective Corrective Actions Assigned Following a May 2001 Trip of the "C" RHR System Pump During SDC Operation.

2. Forced Outage Following the Main Transformer Fire of June 18, 2004.

a. Inspection Scope (partial sample)

The inspectors'evaluated the following forced outage activities to verify that Entergy considered risk when developing outage schedules; that Entergy adheredto administrative risk reduction methodologies for plant configuration control; and to ensure that Entergy adhered to their operating license, Technical Specification requirements, and approved procedures:

Review of the Outage Plan - The inspectors reviewed the shutdown risk assessment to verify that Entergy addressed the outage's impact on defense-in-depth for the five shutdown critical safety functions; electrical power availability, inventory control, decay heat removal, reactivity control, and containment. The daily risk up-date, accounting for schedule changes and unplanned activities were also periodically reviewed; Monitoring of Shutdown Activities - The inspectors observed the shutdown of the reactor plant including reactor plant cooldown activities and transition to shutdown cooling operations. As soon as practical following the shutdown, the inspectors performed walkdowns of the primary containment; DHR System Monitoring - The inspectors monitored decay heat removal on a daily basis. Monitoring included daily reviews of residual heat removal system Enclosure

15 alignment, reviews of spent fuel pool cooling system alignment, and reviews of RCS time-to-boil calculations and results; and Inventory Control - The inspectors performed daily RCS inventory control reviews including reviews of available injection systems and flow paths to ensure consistency with the outage risk plan. The inspectors also ensured that operators maintained RCS level within established ranges.

The inspectors also verified that Entergy identified problems related to the forced outage and entered them into their corrective actions program.

b. FindinQs No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope (eight samples)

The inspectors observed surveillance testing to verify that the test acceptance criteria specified for each test was consistent with Technical Specification and UFSAR requirements, was performed in accordance with the written procedure, the test data was complete and met procedural requirements, and'the system was properly returned to service following testing. The inspectors observed selected pre-job briefs for the test activities. The inspectors also verified that discrepancies were appropriately documented in the correctiveaction program. The inspectors verified that testing in accordance with the following' procedures met the above requirements:

OP 4031, "Type B and C Primary Containment Leak Rate Calculations and Evaluations";

• OP 4100, "ECCS Integrated Automatic Initiation Test";

• OP 4114, "Standby Liquid Control [SLC] System Surveillance,",Section C, "Flow Test Directly into the Reactor Vessel," and Section I, "SLC Explosive Charge Continuity Check"; I OP 4121, "Reactor Core Isolation Cooling System Surveillance," Section B, "RCIC Injection Check Valve (RCIC-22) Test";

OP 4142, "Vernon Tie and Delayed Access Power Source Backfeed Surveillance";

OP 4424, "Control Rod Scram Testing and Data Reduction," Section B, "Single Rod Scrams Using ERFIS Data Collection";

OP 4430, "Reactivity Anomalies/Shutdown Margin Check," Section 1, "Strongest Control Rod Withdrawn Subcritical Check; and Special Test Procedure (STP) 2003-004, "Power Ascension Test Procedure.

b. Findings No findings of significance were identified.

Enclosure

16 1 R23 Temporary Modifications (71111.23)

,a. Inspection Scope (two samples)

The inspectors reviewed the following temporary modifications (TMs) to ensure that the modifications did not adversely affect the, availability, reliability, or functional capability of any risk-significant structures, systems, and components:

TM 2003-039, "Bottom Head Drain Line Freeze Seal"; and TM 2003-022, "Vibration Monitoring Equipment Installation on MS & FW Piping."

The inspectors compared the information in the TM packages to Entergy's TM requirements contained in AP 0020, "Control of Temporary and Minor Modifications."

The inspectors also walked down accessible portions of these TMs to verify that required tags and markings were applied and that the TMs were properly maintained.

The inspectors also reviewed a sample of TM-related problems identified in the -

Entergy's corrective action program to verify that they had identified and implemented appropriate corrective actions.

b. FindinQs No findings of significance were identified.

Cornerstone: Emergency Preparedness 1EP6 Drill Evaluation (71114.06)

a. Inspection Scope (one sample)

On June 17, 2004, the inspectors observed an operating crew evaluate a simulator-based event using the station emergency action levels (EALs) during licensed operator

,requalification training activities. The inspectors discussed the performance expectations and results with the lead instructor and operations training manager. The inspectors focused on the ability of licensed operators to perform event classification and make proper notifications in accordance with the following station procedures and industry guidance:

• AP 0153, Operations Department Communications and Log Maintenance";

• AP 0156, "Notification of Significant Events";

• AP 3125, "Emergency Plan Classification and Action Level Scheme";

• DP 0093, "Emergency Planning Data Management";

• OP 3540, "Control Room Actions During an Emergency"; and

• Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 2.

b. Findings Enclosure

17 No findings of significance were identified.

2. RADIATION SAFETY Cornerstone: Occupational Radiation Safety 20S1 Access Control to Radiologically Significant Areas (71121.01) *'

a. Scope (fourteen samples) '-

The inspectors conducted inspections to verify that Entergy was properly implementing physical, engineering, and administrative controls for access to high radiation areas, and other radiologically controlled areas, and that workers were adhering to these controls when working in these areas. Implementation of the access control program was reviewed against the criteria contained in 10 CFR 20, Technical Specifications, and approved Entergy procedures. The inspectors conducted independent radiation surveys and observed work area conditions, reviewed radiation surveys of these areas, and reviewed electronic dosimetry set points and other exposure controls specified in the radiation work permits (RWPs) that provided the access control requirements for the following radiologically significant work activities:

• Steam dryer underwater welding modifications;

• Drywell shielding installation;

• " Drywell in-service inspection of core spray nozzle N5A;

• Drywell safety relief valve maintenance;

• Drywell main steam isolation valve maintenance; and

• Feedwater heater replacement modifications

b. Findings No findings of significance were identified.

20S2 ALARA Planning and Controls (71121.02)

Inspection Scope (four samples)

The inspectors reviewed Entergy's As Low As Reasonably Achierable (ALARA)

Program performance against the requirements of 10 CFR 20.1101 (b). The inspectors reviewed aspects of the implementation of exposure reduction requirements based on ALARA planning for the five highest exposure outage tasks. The ALARA-related work' activities observed are listed in Section 20S1 above. In addition, the following ALARA inspection activities were conducted:

• Independent shielding effectiveness radiation surveys conducted in the drywell;

• Observation of closed circuit television equipment and tele-dosimetry use in the drywell was conducted with respect to drywell remote health physics work surveillance capability and technical specification requirements; and Enclosure

18 Feedwater heater bay source term location was reviewed relative to worker occupancy areas.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES (OA) 40A1 Performance Indicator Verification (71151)

a. Inspection Scope (two samples)

The inspectors sampled Entergy submittals for the performance indicators (PIs)ylisted below for the period from April 2003 to March 2004. The PI definitions and guidance contained in NEI 99-02 and AP 0094, "NRC Performance Indicator Reporting," were used to verify the accuracy and completeness of the PI data reported during this period.

Barrier Integrity Cornerstone

• *Reactor Coolant System Specific Activity; and

• Reactor Coolant System Leakage.

The inspectors reviewed selected operator logs, plant process computer data, condition reports, and monthly operating reports for the period April 1, 2003, through March 31, 2004.

b. Findings, No findings of significance were identified.

40A2 Identification and Resolution of Problems (71152)

1. Routine Review of Identification and Resolution of Problems

/

a. Inspection Scope The inspectors routinely reviewed issues during baseline inspection activities and plant status'reviews to verify they were being entered into Entergy's corrective action system at an appropriate threshold and that adequate attention was being given to timely corrective actions. Additionally, in order to identify repetitive equipment failures and/or" specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into Entergy's corrective action program. This review was accomplished by reviewing selected hard copies of condition reports (a listing of CRs reviewed is included in the Attachment to this report) and/or by attending daily screening meetings.

Enclosure

19

b. Findings No findings of significance were identified.

2: Semi-Annual Trend Review

a. Inspection Scope As required by Inspection Procedure 71152, "Identification and Resolution of Problems,"

the inspectors performed the semi-annual trend review to identify trends, either licensee or NRC identified, that might indicate the existence of a more significant safety issue.

Included within the scope of this review were:

• CRs generated from January through May 2004;

(

• Corrective maintenance backlog listings from January through May 2004;

• The corrective action program 3rd and 4 th quarter, 2003 trend report; and

• Daily review of main control room operator logs.

b. Findings No findings of significance were identified.

3. Cross-Reference to PI&R Findings Documented Elsewhere Section 1R20.1 describes a finding wherein Entergy personnel did not develop effective corrective actions to prevent recurrence following a 2001 event wherein control room operators did not verify a suction path existed prior to starting the RHR system pump being used to support SDC operations which caused the pump to trip. Entergy's corrective actions relied on the operator's skill to verify a suction path was open prior to restarting the RHR pump rather than proceduralize the step. As a result, an identical event occurred in April 2004 again resulting in a trip of the RHR pump being used to support SDC operations.

40A3 Event Followup (71153)

1. Main Transformer Fire and Reactor Plant Scram

a. Inspection Scope (1 sample)

The inspectors evaluated Entergy's response to a main transformer fire and resultant reactor plant scram that occurred on June 18, 2004. The inspectors immediately responded to the main control room to observe reactor plant parameters, to evaluate individual safety system responses, and to evaluate licensed operator responses to the event. The inspectors evaluated the response of the reactor plant and the licensed operators against Entergy approved operating procedures, abnormal operating procedures, and emergency operating procedures. The inspectors evaluated Entergy's classification of the event (i.e., Unusual Event) in accordance with approved EAL Enclosure

20 procedures to ensure notifications were made to NRC and state/county governments as required. The inspectors also evaluated the ability of Entergy's fire brigade and automatic fire protection systems to extinguish the main transformer fire in a safe and timely manner.

The NRC Region I Office dispatched two inspectors, each a specialist in the areas of electrical and fire protection systems, to assist the resident inspectors-with event follow-

- up activities. The inspectors monitored Entergy's efforts in determining the root cause of the event; monitored Entergy's efforts for the recovery, replacement, and repair of the effected portions of the 22KV electrical system; and monitored Entergy's reactor plant restart preparation activities.

b. Findings Entergy has identified that the root cause of the main transformer fire relates to weaknesses with the preventive maintenance performed on the 22 KV electrical system.

Because additional information is needed to determine ifthese issues are more than minor, they are considered to be an unresolved item (URI) pending completion of the inspectors review of Entergy's root cause analysis: URI 050027112004003-02, Weaknesses Identified with the Preventive Maintenance Performed on the 22 KV Electrical System Resulted in Main Transformer Fire.

40A5 Other Activities

1. Temporary Instruction (TI) 2515/156, "Offsite Power System Operational Readiness."

a. Inspection Scope The inspectors collected and reviewed information pertaining to the Vermont Yankee offsite power system as it related to the requirements of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plarnts"; 10 CFR

.50.63, "Loss of All Alternating Current Power"; offsite power operability; and corrective actions. The inspectors also reviewed this data against the requirements of 10 CFR 50, Appendix A, General Design Criterion 17, "Electric Power Systems," and the Vermont Yankee Technical Specifications. This information was forwarded to NRR for further review. A listing of documents reviewed is included in the Attachment to this report.

b. Findings No findings of significance were identified.

40A6 Meetings, includinq Exit Resident Exit On July 12, 2004, the resident inspectors presented the inspection results to Mr. Kevin Bronson and members of his staff. The inspectors asked whether any materials Enclosure

21 examined during the inspection should be considered proprietary. No proprietary information was identified.

Meeting with the State of Vermont Public Service Board On June 28, 2004, Region I and NRR staff met with. the Vermont State Public Service Board (PSB) regarding Vermont Yankee's request for a 20% extended power uprate.

The NRC staff discussed the NRC's power uprate review process and details regarding a planned pilot engineering inspection slated for Vermont Yankee in August 2004.

ATTACHMENT: SUPPLEMENTAL INFORMATION

/ E-Enclosure

A-1 SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee Personnel:

J. Thayer Site Vice President K. Bronson General Plant Manager J. Allen . Design Engineering P. Corbett Maintenance Manager J. Dreyfuss Project Engineering Manager J. Devincentis Licensing Manager W. Fadden Design Engineering J. Geyster Radiation Protection Superintendent D. Giorowall- Programs Supervisor Dennis Girrior Programs Supervisor S. Goodwin Mechanical Design Department Manager M. Gosekamp Superintendent of Operations Training M. Hamer Licensing D. Johnson Design Engineering Dave King ISI Coordinator R. Morissette Principal As Low As Reasonably Achievable (ALARA) Engineer M. Pletcher Radiation Protection Supervisor - Instruments P. Rainey, Design Engineering B. Renny Supervisor, Access Authorization K. Stupak Technical Training C. Wamser Operations Manager R. Wanczyk Director of Nuclear Safety LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened and Closed

(-

0500271/2004003-01 NCV Ineffective Corrective.Actions Assigned Following a May 2001 Trip of the "C" RHR System Pump During SDC Operation (Section 1R20.1)

Opened 0500271/2004003-02 URI Weaknesses Identified with the Preventive Maintenance Performed on the 22 KV Electrical System Resulted in Main Transformer Fire (Section 40A3.1)

Attachment

A-2 LIST OF DOCUMENTS REVIEWED Section 1R02: Evaluation of Chancqes, Tests, or Experiments Power UDrate Modifications TM 2003-022 ,Vibration Monitoring Equipment Installation on MS [Main Steam] & FW

[Feedwater] Piping MM 2003-015 Reactor Feed Pump Suction Pressure Trip MM 2003-016 Reactor Recirculation System Runback" MM 2003-026 AST [Alternate Source Term] Component Modification (OG-779 Installation)

MM 2003-028 APRM Flow Control Trip Reference Card Replacement MM 2003-039 NSSS [Nuclear Steam Supply System]/BOP [Balance of Plant]

Instrumentation Upgrades MM 2003-054 381 Line Overload Relay Setting VYDC 2003-013 Installation of Additional Main Steam Safety Valve Section 1R08: Inservice Insoection Procedures ENN-NDE 9.29, Rev 0 for UT of structural overlay (weld N5A)

PDI-UT-8, Rev B. Generic Procedure for UT of Weld Overlaid Austenitic Pipe Welds ISI - 254, Rev 5, for remote ISI of RPV Welds NE 8048, Rev 1 - In Vessel Visual Inspection Drawings ISI-PPV-1 03, Rev 3. Reactor Vessel ISI-SLC-Part 4, Rev 3. SLC Piping ISO D-7983-621 Rev G. UT/ET clad crack calibration block 6D3004,7, Rev 0, Wesdyne Calibration Standard PDI-01 Miscellaneous Reports QA (Quality Assurance) Audit Report AR-2003-22b&c, dated 11/13/2003 GE (General Electric) RICSIL No. 050 of 4/23/1990, and GE SIL NO. 539, dated 11/5/1991 GE Reports INR-VYR24-04-01.R2, 02R2, 03, & 04R1 on Steam Dryer Visual Indications GE Nuclear Engineering (GENE) 0000-0028-0130-01, Revision 3, dated April 2004 on Steam Dryer Unit End Plate Indications - Vermont Yankee R24 GENE-0000-0028-0130-02, Revision 3, dated April 2004 on Steam Dryer Drain Channel Indications - Vermont Yankee R24 Section 1R17: Permanent Plant Modifications Power Uprate Modifications Attachment

A-3 MM 2003-015 Reactor Feed Pump Suction Pressure Trip MM 2003-016 Reactor Recirculation System Runback MM 2003-026 AST Component Modification (OG-779 Installation)

MM 2003-028 APRM Flow Control Trip Reference Card Replacement MM 2003-039 NSSS/BOP Instrumentation Upgrades MM 2003-054 381 Line Overload Relay Setting Calculations Vermont Yankee Calculation (VYC) 0693A Rev. 2 APRM Neutron Monitoring Trip Loops VYC-2269 Rev. 0 Feedwater and Condensate Hydraulic Model Analysis VYC-2309 Rev. 0 Steam Drain Line MS-1 89-D3 Check Valve Addition License Amendment Documents BVY 03-23 License Amendment Proposal for ARTS/MELLLA BVY 03-39 Technical Specification Proposed Change # 257 (ARTS/MELLLA)

GE-NE-0000-0020 Entergy Nuclear Operations Incorporated Vermont Yankee Nuclear Power GE-NE-1500-0001 Station MELLLA+ Transient Analysis NEDO-33090 Safety Analysis Report for Vermont Yankee Nuclear Power Station Constant Pressure Power Uprate NRC NRR Safety Evaluation for License Amendment No. 219 to DPR-28 Specifications/Procedures AP 5226 Rev. 5 Calibration of, Switchyard Breaker Failure Relays VYSP-FS-074 Specifications for Safety Valves VY IPE Vol 2 Individual Plant Examination for SRV/SV Reclosure Section 4'0A2.1: Routine Review of Problem Identification and Resolution Condition Reports 2002-2581 RBCCW pumps failed to restart within time limit during ECCS [emergency core isolation cooling] test 2002-2584 ECCS test data was accepted as satisfactory when some data was outside of acceptance criteria 2003-1509 The "C" RHRSW pump cooling water supply solenoid valve failed to open as required on pump start 2003-2321 No indicated cooling flow upon "C" RHRSW pump start 2004-0700 While troubleshooting a 4KV breaker on Bus-2-7, the breaker driving pawl broke

• 2004-0840 Incorrect status of Decay Heat Removal was logged on the Critical Outage Systems Status Form

• 2004-0845 NRC resident question on RHR procedure wording 2004-0879 HPCI V23-845 failed IST testing 2004-0892 Water level in the reactor cavity exceeds limits during cavity floodup Attachment

A-4

• 2004-0897 Incorrect start dates used in ORAM-Sentinel for alternate DHR capability determinations 2004-0918 Adverse trend - main steam isolation Valve Appendix J test failures 2004-0942 HPCI V23-846 failed IST testing 2004-0955 As-found condition of V2-80 included a galled stem 2004-0968 Unsuccessful decon of diver 2004-0981 An observation was made from below vessel that a piece of control rod drive housing support (shoot-out steel) was missing 2004-0986 Instructions for RWP not adhered to 2004-0998 RHR-46A allowed to overflow while working on the valve 2004-1005 B RHR pump trip during restart due to no suction path 2004-1017 V2-13-3 failed Appendix J local leak rate test 2004-1058 Flow noise from RO-10-105C, "C" _RHR pump discharge orifice 2004-1091 Rad survey maps indicate need to perform alpha survey

\2004-1117 Flow noise from "C" RHR pump discharge orifice 2004-1160 ASME rejectable indication on SLC weld 2004-1190 Weld electrodeoven left unlocked and unattended

• 2004-1339 Two fuel segments could not be confirmed in storage container 2004-1409 "A" RBCCW did not start within the allowed ECCS start time 2004-1426 ECCS test exceptions 2004-1428 Reactor water clean up pump started with no suction path 2004-1548 P-8-1A leaking oil from upper bearing reservoir area 2004-1653 Excessive overtime approved without documentation 2004-1665 Potentially non-conservative scram setpoint values

• 2004-1916 #2 fan room has inadequate hose stream coverage due to modification to fan room door

• 2004-1928 Slight leakage on "B" SBGT demister loop seal piping union 2004-1989 Generator Ground alarm came in 2004-2015 Reactor Scram 2004-2017 Notification of Unusual Event (NOUE) declared due to plant fire and automatic reactor scram 2004-2019 Main transformer fire

• 2004-2022 Discrepancy in post scram rod position indication

• 2004-2023 Torus-to-drywell vacuum breaker indicating lights and alarm indicate breakers may have cycled during the scram/transformer trip

• 2004-2045 Repeat of P-8-1A leaking oil from upper bearing reservoir area 2004-2074 Failure to make timely notification of States upon declaration of unusual event on June 18, 2004

• Inspector-identified issues.

Section 40A5.1: Temporary Instruction (TI) 2515/156, "Offsite Power System Operational Readiness."

Procedures Attachment

A-5 Vermont Yankee Operating Procedure Form (VYOPF) 0150.03, "CRO [Control Room Operator]

Round Sheet AP 0172, "Work Schedule Risk Management - On Line" ISO New England Master/Satellite Procedure #1, "Nuclear Plant Transmission Operations,"

Revision 0 ISO New England Master/Satellite Procedure #2, "Abnorrnal Conditions Alert," Revision Dated 11/19/01 Licensee Event Reports (LERs)

Vermont Yankee Nuclear Power Station LER 87-008-00, "Loss of Normal Power During Shutdown Due to Routing All Off-Site Power Sources Through One Breaker" Vermont Yankee Nuclear Power Station LER 84-022-00, "Diesel Generator Lockout Trip of Both Generators" Maintenance Rule Documents NRC Maintenance Rule Program Website Frequently Asked Questions (FAQs)

Vermont Yankee 10CFR50.65 NRC Maintenance Rule SSC Basis Document, "345K Volts AC Electrical (345KV)"

Vermont Yankee 10CFR50.65 NRC Maintenance Rule SSC Basis Document, "115K Volts AC Electrical (115KV)".

Operational Experience Documents JA Fitzpatrick Operational Experience (OE) 16822, "Reactor Scram due to Grid Instability" Significant Operating Experience Report (SOER) 9901, "Loss of Grid" Miscellaneous Documents Control room operator logs dated 8/17/87 VYC-1088, "VermontYankee 4160/480 Volt Short Circuit/Voltage Study," Revision 3 Attachment

A-6 LIST OF ACRONYMS AC Alternating Current ADAMS Automated Document Access Management System ALARA As Low As Is Reasonably Achievable AP Vermont Yankee Administrative Procedure APRMs Average Power Range Monitors ASME American Society of Mechanical Engineers CFR Code'of Federal Regulations CR Condition Report CRO Control Room Operator CS Core Spray CY Calendar Year DBD Design Basis Document DHR Decay Heat. Removal DOST Diesel Oil Storage Tank DP Vermont Yankee Department Procedure EALs Emergency Action Levels ECCS Emergency Core Cooling System EDGs Emergency Diesel Generators ET Eddy Current Testing EOP Emergency Operating Procedure ER Event Report FAQ Frequently Asked Question FW Main Feedwater System GE General Electric GENE General Electric Nuclear Engineering HPCI High Pressure Coolant Injection IMC Inspection Manual Chapter IPEEE Individual Plant Examination External Events IR Inspection Report ISI Inservice Inspection IST Inservice Testing KV Kilovolt LER Licensee Event Report LLRT Local Leakage Rate Testing MM Minor Modification MS Main Steam System NCV Non-Cited. Violation NDE Nondestructive Examination NEI Nuclear Engineering Institute NOUE Notice of Unusual Event NRC Nuclear Regulatory Commission NRR NRC Office of, Nuclear Reactor Regulation OE Operating Experience ON Vermont Yankee Off-Normal Procedure OP Vermont Yankee Operating Procedure Attachment

A-7 P1 Performance Indicator PMT Post Maintenance Testing PSB Public Service Board QA Quality Assurance RCS Reactor Coolant System RCIC Reactor Core Isolation Cooling RFO Refueling Outage RHR Residual Heat Removal RHRSW Residual Heat Removal Service Water RPS Reactor Protection System RWP Radiation Work Permit SBGT Standby Gas Treatment SDC Shutdown Cooling SDP Significance Determination Process SEG Simulator Evaluation Guide SEN Significant Event Notification SFP Spent Fuel Pool SLC Standby Liquid Control SOER Significant Operating Experience Report SSC Structures, Systems and Components STP Special Test Procedure SW Service Water TI Temporary Instruction TM Temporary Modification UFSAR Updated Final Safety Analysis Report URI Unresolved Item UT Ultrasonic Testing VT Visual Examination Testing VY Vermont Yankee VYC Vermont Yankee Calculation VYDC Vermont Yankee Design Calculation VYOPF Vermont Yankee Operating Procedure Form Attachment

NEC-JH .-59 Entergy REPORT fCRN-TY-2007-02133

,'CONDITION --

Originator: Fales,Neil Originator Phone: 8024513057' Originator Group: Eng P&C Codes Staff Operability Required: Y Reportability Required: Y Supervisor Name: Lukens,LarryD Discovered Date:. 05/28/2007 17:06 Initiated Date: 05/28/2007 17:11 Condition

Description:

Steam Dryer Inspection Indications During RF026 reactor vessel inspections, linear indications on -the Steam Dryer Interior Vertical Weld HB-V04 were identified by General Electric. Most of these indications were previously identified in RF025 with nodiscemable changes noted in RFO26. One new relevant indiction A-as observed of similar appearance, orientation and: size as those previously seen.. These were documented via GE's process by INRVVI-VYR26-07-10. See attached GE INRs for details.

ImmediateAction

Description:

Notified' Supervisor and generated CR.

Suggested Action

Description:

.The new indication will need to be evaluated.

EQUIPMENT:

Tag Name T'ag Suffix Name Component Code Process System Code STEAM-DRYER RZEACTOR MR=Y NB TRENDLNG (For Reference Purposes Only):

Trend Type Trend Code KEYWORDS KW-PRE-SCREENED FOR MRFF 1NPO BINNING ER1 KEYWORDS KW-ISI REPORT WEIGHT EM ESPC HEP FACTOR E Attachments:

Condition Description GE INrR 10

F Entergy ADMIN CR-VTY-2007-02133 Initiated Date: 5/28/2007 17:11 Owner Group :Eng P&C Codes gmtgn Current

Contact:

Cvw.

Current Significance: C - INVEST &CORRECT Closed by: Taylor,James M 6/18/2007 16:06

(

Summary

Description:

Steam Dryer Inspection Indications During RF026 reactor vessel inspections, linear indications on the Steam Drver Interior Vertical Weld HB-V04 were identified by General Electric. Most of these indications Nvere previously identified in RF025 x\ith no discernable changes noted in RF026. One ne'w relevant indication was observed of similar appearance, orientation and size as those previously seen. Tlhese were documented via GE's process by INR-IVVI-VYR26-07-10. See attached GE INR's for details.

Remarks

Description:

Closure

Description:

CR closure review performed.

/

Attachment Header Document Name:

ntitled -".. "

Document Location Att

Title:

ption Attach

Title:

IN... .....

iNR-W~I~:VR26,,7 Steam Dryer fintrior HBV04 Indication Notification Report Plant/1Unit- Component Description Refetrence,(s)

D~vD DISK IlVYR6075 Title 4 Steam Dryer RFOY-25 IVVI Report INF V002.

Interior Vertical:Weld:

RF026 Sp.r..g20Q7 HB-V04 B$ackgrounid During the~VoIrrnofft'Yankq? 2007 refueOling utage inacordano with the'i Yankee VT-VMY.204V1 0 Lfrm iivRO2 Procedure, the Steam Dryer was inspected. The dryer inspection Inc1uded Inspection of the Steam Dryer Intemior welds and compnnprPfts. These. inlspectionls welre do~ne with G~E's Fire Fly. ROV with color camera, During the i nspe~cti~on of the HB-V04 weld (Dryer Unit i-lood, endPanel to HB-PL3 Plate weld), relevant linear indicalions~were sbSee~d inithe heata~ffeced zone on the Dryer;Unite side.'of~he weld. Most of these linear indicationsawee previousIy

,seen-in RFO-25,, ReterenceANF #002. Whencomparing V this outage with last retevanthidibation is i.6utage,.onenew seen (3 indication) :of similar appearance, brientation and size as those previousioseen; on6 indication was not seen (RF2O5: 3th indication). Nob dcernible,,chtange was noted inthohse indicationis Whibdh ,eldeatet to those of RF026.

S~eeattached 2007 photos and skethes.

• 20 A 90'?

$ketchý on the left shows the weld miap roll out The sketch, on the right show's a bottom vlew of the dryer.

preopard b : Dick~ Hoomr.. 512~710 0ae Re.vi .wed by, R*dne ,Draiih Dte: 05/27/07 UVtilit'y ;ReOview By, Da'te- ~A~

Page 1 of"8,

GE NuclearEnergy INR-IWI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo shows the interior of the dryer and the location of HB-V04 vertical weld.

This 2007 photo shows the top of the vane bank (on the left) and the end panel (on the right) and the vertical weld in the center INR-IWI-VYR26-07-10 Stam Dryer Int HB-V04.doc Page 2 of 8

GE NuclearEnergy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo is of the 1 indication from top down (Correlates to RF025: V=1 indication).

This 2007photo is a close-up of the 1= indication (Correlates to RF025: 1 indication).

INR4WI-VYR26-07-10 Steam Dryer Int HB-V04 oc Page 3 of 8

GE Nuclear Energy INR-IWI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This 2007 photo is the 2 "dindication (Correlates to RF025: 2 nd indication).

This is a 2007 photo of the 3rd indication and is a new RF026 indication.

INR.4WVV-VYR2".07-10 Steam Dryer Int HB-V04.doc Page 4 of 8

GE Nuclear Energy INR-IWI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 4th indication (Correlates to RF025: 3 rd indication)

This is a 2007 photo of the 5th indication (Correlates to RF025: 4th indication).

INR-IWI-VYR26-07-10 Steam Dryer Int HB-VO4.doc Page 5 of 8

GE Nuclear Energy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 6th indication (Correlates to RF025: 5th indication).

This is a 2007 photoof the 7th indication (Correlates to RF025: 6th indication).

INR4WI-VYR26-07-10 Steam Dryer Int HB-V04.doc Page 6 of 8

GE NuciearEnergy INR-IWI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 8th indication (Correlates to RF025: 7th indication).

These 2007 photos show a linear indication and change of lighting and show a non-relevant indication (Correlates to RF025: 9t indication).

INR-IWI-YR26-07-10 Steam Dryer Int HB-V04.doc Page 7 of 8

CE NuclearEnergy INR-IVVI-VYR26-07 Steam Dryer Interior HB-V04 Indication Notification Report This is a 2007 photo of the 9"' indication (Correlates to RF025: 10th indication).

This is a 2007 photo of the bottom weld area and crud line.

INR4WI-VYR26-07-10 Steam Dryer Int HB-V04 doc Page 8 of 8

Entergy OPERABILITY CR-VTY-2007-02133 OperabilityVersion: 1 Operability Code: EQUIPNENT FUNCTIONAL Immediate Report Code: NOT REPORTABLE Performed By: Brooks,James C 05/29/2007 21:07 Approved By: Faupel,Robert F 05/30/2007 00:30 Operability

Description:

Currently the plant is shutdown with the bolt in place. The bolt has one crimp fully engaged preventing the bolt from backing out. The need for having both crimps fully engaged will have to be evaluated prior to startup.

Approval Comments:

Entergy ASSIGNMENT S, CR-VTY-2007-02133 Version: 2

.Significance Code: C - INVEST & CORRECT Classification Code: C Owner Group: Eng P&C Codes Mgmt.

Performed By: Wren,Vedrana 05/30/2007 13:04 Assignment

Description:

(

Entergy AS S I G N ME NT S CR-VTY-2007-02133 f

NVersion: 1 Significance Code: C - INVEST & CORRECT.

Classification Code: C Owner Group: Eng P&C Codes Mgmt Performed By: Lukens,Larry D 05/29/2007 04:46 Assignment

Description:

self identified outage constraint I

F Entergy REPORTABILITY CR-VTY-2007-02133

-I I lReportability Version: 1 (

Report Number:

Report Code: NOT REPORTABLE Boilerplate Code: NOT REPORTABLE Performed By: Devincentisjames M 05/29/2007 08:09 Reportability

Description:

Not reportable - This condition does not meet the Reportability screening criteria contained in APOO10 or APO 156. The Steam Dryer is NNS andperforms no safety releted functions. VY has a commitment to provide the results of the steam dryer inspections to the NRC following startup.

I

Entergy I CORRECTIVE ACTION CR-VTY-2007-02133

!I CA Number: I CAoup Name Assigned By: CRG/CARB/OSRC Assigned To: Eng P&C Codes Mgmnt LukensLarry D Subassigned To: Eng P&C.Codes Staff Fales,Neil Originated By: Wren,Vedrana 5/30/2007 13:00:53 Performed By: Lukens,Larry D 6/15/2007 13:17:25 Subperformed By: Fales,Neil 6/15/2007 11:49:49 Approved By:

Closed By: Taylor,James M 6/18/2007 16:02:38 Current Due Date: 06/28/2007. Initial Due Date: 06/28/2007 CA Type: DISP - CA Plant Constraint: 0 NONE CA

Description:

C - INVEST & CORRECT (Review CR for full details>

oThe CRG has initially classified this CR as "C" INVEST & CORRECT 0I Per the CRG, Perform an Investigation of the issues identified in this CR and determine if additional actions are

]required within 30 days.

[iEnsure all Screening Comments have been addressed in the investigatiori"- (CR assignment tab)

.. Develop adequate corrective actions and issue CAs. (Due Dates per LI 102 Attachment 9.4)

[OLT CAs Require Approval from Site VP/GMPO or Director prior to initiating. Completionrof Attachment 9.9 LTCA E[!Classification Form is required.

Response

Approved. No additional corrective action required. Therefore, this CR may be closed. LI-102 Closure Statements follow:

CR CLOSURE STATEMENTS FROM LI-102:

oZIThe root cause or apparent cause is valid. VERIFIED oO]The specific condition is corrected or resolved. VERIFIED oFOverall plant safety is not inadvertently degraded.. VERIFIED o[ Generic implications of the identified condition are considered, as appropriate. VERIFIED oZIActions were taken to preclude repetition, as.appropriate. VERIFIED ooAny potential operability or reportability issues identified during the resolution of the condition have been appropriately addressed. VERIFIED o.]All corrective action items are completed. VERIFIED o0]Effectiveness Reviews have been initiated via use of Learning Organization CR, when applicable. VERIFIED Subresponse: /

The new indication was evaluated by Code Programs, see the attached document. The evaluation accepts the indication as

• is with no repair required. The steam dryer will be inspected per the same scope in RF027 and. RF028 per letter BVY 04-097,. therefore the area of this indication will be inspected again during the next two outages.

Neil Fales 6/15/07 Closure Comments:

l Entergy CORRECTIVE ACTION CR-VTY-2007-02133 Attachments:

Subresponse Description Evaluation

Attachment Header Document Name:

Document Location

• ubresponse Description Attach

Title:

JEvaluation ................... : ...... ,*......

ATTAcHMENT'9A ENGINEERING RePORT COVER SMET & INSTRuc-nms SHEET 1 0F2 Engineering v - ReportNo.

. VY-RPT-07-l00011 Rev. 2 Page I of 3 w- i nwft ENTERGY NUCLEAR Engineering Report Cover Sheet Engineering Report

Title:

EVALUATION OFNEW RFO26 STEAM DRYER INDICATION Engineering Report. Type:

New 0 1 Revision I1. Cancelled [] Superseded I]

Applicable Site

-1P3 0 JAS

• PNPS: 0I vY* wpo 5 ANI 0 .ANO2 ECH [] GGS I RBS 0 WF3 Ii DRN No. ENiA;"[@EC'1772 ReportOrigin: 0 Entergy 0] Vendor Vendor Document No.:_..- _

Quality.-Related: 0, Yes 0, No Preparedby: Neil' Pales! ,"jJ 4 Date:

Responsible Engineer (Print Name/Sign)

Design Verified/ N/A Date:

Design Verifier (if re quired): (Print Namne/Sign)

Reviewed by:

Scott Groodwin/ 7111 Date: "/5-67 Reviewed (Pri Name/Sign)

Reviewed by*: N/WA Date:

ANI Ifreq'Air.mt'Name/..1D)p Approved .by: Larry Lukens/! , Date:__ _ _

Supervisor (ýY f/Sign)

• For ASME Section XI ode Programplans per ENN'-DC-120, if require

NEC-JH_60 STATE OF VERMONT PUBLIC SERVICE BOARD DOCKET NUMBER 7195 PETITION OF>VERMONT DEPARTMENT OF PUBLIC SERVICE FOR AN INVESTIGATION INTO THE RELIABILITY OF THE STEAM DRYER AND RESULTING PERFORMANCE OF THE VERMONT YANKEE NUCLEAR POWER STATION UNDER UPRATE CONDITIONS.

Technical Hearing held before Board Members of the Vermont Public Service Board, at the Third Floor Conference Room, Chittenden Bank Building, 112 State Street, Montpelier, Vermont, on August 18, 2006, beginning at 9:30 a.m..

EXCERPT FROM PAGES 9-10 OF TRANSCRIPT

(\

Redirect by John Marshall for ENVY JOHN R. DREYFUSS- ENVY HEAD OF ENGINEERING- NOW HEAD OF NUCLEAR SAFETY ASSURANCE 4 SURREBUTTAL BY MR. MARSHALL:

5 Q. I have one question on live surrebuttal. Mr.

6 Dreyfuss, Mr. Sherman testified yesterday that it can be 7 difficult to distinguish IGSCC cracking related to uprate 8 and uprate relatedfatigue cracking. He also testified 9 with respect to the Department's recommendations 10 concerning dispute resolution with respect to an extended 11 ratepayer protection plan. Do you recall those questions

. 12 and answers yesterday?

13 A. I do.

14 Q. My question is given his testimony about the 15 difficulty of distinguishing IGSCC cracking and fatigue 16 cracking related to uprate circumstances, does this give 17 any concerns to the company about dispute resolution under 18 an extended ratepayer protection plan?

19 A. Yes it does,. and I do agree that you know it 20 sometimes is very difficult to distinguish or 21 differentiate between the type of cracking that you see 22 with this intergranular stress corrosion cracking, IGSCC, 23 and fatigue cracking. It can be particularly difficult 24 when you're trying to do this work underwater as well.

25 So you know there are cases where it's clear 1 and clean cut and the way that the kind of characteristics 2 of this type of cracking where you can tell, but other 3 cases that I have seen and have been brought to me you 4 know it's less clear.

5 The other point that I think is important here 6 too is that we are going to be shutting Vermont Yankee 7 down for a refuel outage in May of next year and it's 8 absolutely clear that we will see cracks. There were, 9 cracks before power uprate. You know we have evaluated 10 all of them. They are not structurally significant, but 11 there will be cracks and there can be debate about those 12 cracks. If there's an IGSCC crack, there could be debate 13 about whether it's IGSCC or otherwise or fatigue type of 14 crack. So, you know, again these are not clear and easy 15 distinctions to make in every case.

NEC-JH_61 April 18, 2007 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of )

Entergy Nuclear Vermont Yankee, LLC ) Docket No. 50-271 -LR and Entergy Nuclear Operations, Inc. ) ASLBP No. 06-849-03-LR

• )

(Vermont Yankee Nuclear Power Station) )

DECLARATION OF JOHN R. HOFFMAN IN SUPPORT OF ENTERGY'S MOTION FOR

SUMMARY

DISPOSITION OF NEC CONTENTION 3 John R. Hoffman states as follows under penalties of perjury:

I. Introduction

1. Prior to September 2006 1 was employed by Entergy Nuclear Operations, Inc.

("Entergy") and had, among other responsibilities, that of Project Manager for the License Renewal Project at the Vermont Yankee Nuclear Power Station ("VY"). I retired from Entergy's employment in September 2006. I am currently a consultant and provide this declaration in support of Entergy's Motion for Summary Disposition of New England Coalition's ("NEC")

Contention 3 ("NEC Contention 3") in the above captioned proceeding.

2. My professional and educational experience is summarized in the curriculum vitae attached as Exhibit 1 to this declaration. Briefly summarized, I have over 37 years of nuclear power engineering experience, and have been associated with VY since 1971.

3. During my employment at VY I had no direct involvement with the power uprate implemented between 2003 and 2006. However, I have reviewed relevant materials and conducted interviews with plant personnel to familiarize myself with the manner in which steam

.dryer issues were addressed during the uprate process. I have personal knowledge of the manner in which VY intends to address the steam dryer during the period of extended operation.

4. NEC Contention 3 asserts that: "Entergy's License Renewal Application does not include an adequate plan to monitor and manage aging of the steam dryer during the period of extended operation." This contention lacks technical or factual basis.

5. I will demonstrate that the plan proposed by VY .for monitoring and managing aging of the steam dryer during the period of extended operation is adequate and is consistent with manufacturer recommendations and the practice in the industry.

II. Background

6. In a boiling water reactor ("BWR"), the steam dryer is a stainless steel component whose function is to remove moisture from the steam before it leaves the reactor. The dryer is mounted in the reactor vessel above the steam separator assembly and is latched to the inside of the vessel wall below the steam outlet nozzles. Wet steam flows upward and outward through the dryer. Moisture is removed by impinging on the dryer vanes and flows down through drains to the reactor water in the downcomer annulus below the steam separators.

7. The steam dryer does not perform a safety function and is not required to prevent or mitigate the consequences of accidents. The VY steam dryer is a non-safety-related, non-Seismic Category I component. Although the steam dryer is not a safety-related component, the assembly is designed to withstand design basis events without the generation of loose parts and the dryer is designed to maintain its structural integrity through all the plant operating conditions.

8. On September 10, 2003, Entergy submitted its application to increase the maximum VY authorized power level from 1593 megawatts thermal ("MWt") to 1912 MWt. This power increase represented an increase of approximately 20% above original rated thermal power and was known as an "extended power uprate" or "EPU". Letter from J. Thayer to NRC, "Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271) Technical Specification Proposed Change No. 263 Extended Power Uprate" (Sept. 10, 2003) ("EPU Application"), ADAMS Accession No. ML032580089.

9. In 2002, steam dryer cracking and damage to components and supports for the main

'steam and feedwater lines were observed at the Quad Cities Unit 2 nuclear power plant. These conditions were detected after implementation of an extended power uprate similar to the one proposed in 2003 for VY. It was determined that loose parts shed by the dryer due to flow-induced vibration-had damaged the supports.

10. In response to this experience and to concerns about steam dryers at other nuclear power plants Entergy substantially modified the steam dryer at VY during the spring 2004 refueling outage to improve its capability to withstand potential adverse flow effects that could result from operation of-the plant at EPU levels. The modifications, intended to increase the F

structural strength of the dryer, are described in Attachment 2 to Supplement 8 (dated July 2, 2004) to the EPU Application, ADAMS Accession No. ML042090103.

HIS VY Steam Dryer Analyses in Support of EPU

11. In addition to making substantial physical modifications to the VY steam dryer, Entergy conducted two categories of activities to assure that the structural integrity of the dryer would be maintained during EPU operations. The first category of activities included performing two types of complementary analyses to evaluate the pressure loads acting on the steam dryer during operation at EPU conditions: the computational fluid dynamics ("CFD") and acoustic circuit model ("ACM") analyses. The calculated loads obtained from the CFD and ACM analyses were inputs to a finite element model (FEM) that calculated peak stresses for specific steam dryer locations. This FEM output was then compared to the fatigue limits for the dryer material specified in the ASME Code.

12. The resulting maximum calculated stresses for EPU conditions were found to be well within the ASME fatigue endurance limit. (The endurance limit is the level of stress that a material can withstand over an infinitenumber of cycles without failure.) The analyses indicated that there is significant margin between the magnitude of the potential stresses imposed on the steam dryer and the level at which fatigue failure would occur.

13. Entergy also installed 32 additional strain gages on the main steam line piping during the fall 2005 refueling outage (beyond 16 strain gages installed previously). The data measured by the strain gages and other complementary instrumentation were monitored frequently during EPU power ascension to verify that the structural limits for the steam dryer were not reached.

This data monitoring was accomplished as the power levels were increased towards EPU.

IV. Steam Dryer Monitoring and Inspection Program During Implementation of EPU

14. As a second set of activities intended to provide independent confirmation of the structural integrity of the steam dryer during operation at uprate levels, VY instituted a program of dryer monitoring and inspections to provide assurance that the structural loadings under EPU conditions did not result in the formation or propagation of vibration-induced cracks on the dryer. The program is described in Attachment 6 to Supplement 33 (dated September 14, 2005) to the EPU Application, ADAMS Accession No. ML052650122. The program was reviewed and approved by the NRC and included as a license condition as part of the power uprate license amendment issued on March 2, 2006 (Exhibit 2 hereto).

15. The monitoring and inspection program measured the performance of the VY steam dryer during power ascension testing and operation as power was increased from the original licensed power level to full EPU conditions. The program included taking daily measurements of moisture carryover and periodic measurements of main steam line pressure. Pursuant to the program, following completion of EPU power ascension testing, moisture carryover measurements have continued to be made periodically, and other plant operational parameters that could be indicative of loss of steam dryer structural integrity continue to be monitored.

16. In addition to monitoring of plant operational parameters, the monitoring and inspection program calls for the steam dryer to be inspected during plant refueling outages in the fall of 2005, spring of 2007, fall of 2008, and spring of 2010. The inspections are conducted in accordance with the recommendations of General Electric's Service Information Letter ("SIL")

No. 644, Revision 1 (Nov. 9, 2004), ADAMS Accession No. ML060120032 ("GE-SIL-644").

The provisions of GE-SIL-644 also govern the manner in which monitoring of plant parameters is being conducted since VY started operating at EPU levels. Plant procedures require that the periodic monitoring activities be conducted in a manner consistent with guidance in GE-SIL-644. See Exhibit 3 (VY Operating Procedure OP 0631, Appendix F).

17. The commitment to conduct dryer monitoring and inspections in accordanc~e with the guidance of GE-SIL-644 is reflected in the above referenced license condition, proposed by Entergy in Attachment 1 to Supplement 36 to the EPU Application (October 17, 2005), ADAMS Accession No. ML052940225, and currently in effect. Entergy is committed to a program for ensuring the structural integrity of the VY steam dryer that consists of the following actions, specified in the VY operating license:

2e. Entergy Nuclear Operations, Inc. shall revise the SDMP [steam dryer monitoring program] to reflect long-term monitoring of plant parameters potentially indicative of steam dryer failure; to reflect consistency of the facility's steam dryer inspection program with

,General Electric Services Information Letter 644, Revision 1; and to identify the NRC Project Manager for the facility as the point of contact for providing SDMP information during power ascension.

5. During each of the three scheduled refueling outages (beginning with the spring 2007 refueling outage), a visual inspection shall be conducted of all accessible, susceptible locations of the steam dryer, including flaws left "as is" and modifications.

6. The results of the visual inspections of the steam dryer conducted during the three scheduled refueling outages (beginning with the spring 2007 refueling outage) shall be reported to the NRC staff within 60 days following startup from the respective refueling outage. The results of the SDMP shall be submitted to the NRC staff in a report within 60 days following the completion of all EPU power ascension testing.

7. The requirements of paragraph 4 above for meeting the SDMP shall be implemented upon issuance of the EPU license amendment and shall continue until the completion of one full operating cycle at EPU. If an unacceptable structural flaw (due to fatigue) is detected during the subsequent visual inspection of the steam dryer, the requirements of paragraph 4 shall extend another full operating cycle until the visual inspection standard of no new flaws/flaw growth based on visual inspection is satisfied.

8. This license condition shall expire upon satisfaction of the requirements in paragraphs 5, 6, and 7 provided that a visual inspection of the steam dryer does not reveal any new unacceptable flaw or unacceptable flaw growth that is due to fatigue.

Exhibit 2 hereto at 2-4.

18. As required by the VY operating license, VY'is operating under a program that provides for long-term monitoring of plant parameters potentially indicative of steam dryer failure plus inspections at three consecutive refueling outages, all in accordance with GE-SIL-644. The monitoring that has been performed since implementation of the EPU, and the inspections conducted to date, confirm that fatigue-induced cracking of the VY steam dryer is

• notoccurring.

19. To summarize, Entergy performed two categories of activities in support of its EPU Application: on the one hand, the CFD/ ACM/ FEM and the associated measurement of stress levels by means of strain gages during power ascension; this set of activities has been completed.

On the other hand, Entergy instituted a monitoring and inspection program, which was initiated during power ascension, is still ongoing, and will be in effect throughout EPU operations. The monitoring and inspection program does not rely on the CFD and ACM analyses.

V. Steam dryer agin! management plan for license renewal period A. Overview

'20. In its License Renewal Application, Entergy addresses aging management of the VY steam dryer as follows:

Cracking due to flow-induced vibration in the stainless steel steam dryers is managed by the BWR Vessel Internals Program. The BWR Vessel Internals Program currently incorporates~the guidance of GE-SIL-644, Revision 1. VYNPS will evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document.

License Renewal Application, § 3.1.2.2.11 "Cracking due to Flow-Induced Vibration."

21. GE-SIL-644 recommends that BWR licensees institute a program for the long term monitoring and inspection of their steam dryers. It provides detailed inspection and monitoring guidelines (see SIL-644, ADAMS Accession No. ML050120032, Exhibit 4 hereto,'Appendices C and D). With respect to monitoring, the guidelines call for the periodic monitoring of parameters that may be indicative of steam dryer failure, particularly moisture carryover:

Moisture carryover should be monitored weekly:

Statistically evaluate the moisture carryover data and qualitatively determine if there is a significant increasing trend that cannot be explained by changes in plant operational parameters. If an unexplained increasing trend is evident, then collect additional moisture carryover data with consideration for increasing the measurement frequency (e.g., from "once per week" to "once per day").

If the latest moisture carryover measurement is greater than "mean plus 2-sigma" and this increase cannot be explained by changes. in plant operational parameters, then obtain a complete set of data for the plant operational parameters (identified above). Compare the current plant operational data with the baseline data to explain the increased moisture carryover (i.e., is there steam dryer damage or not). If an increase in moisture carryover occurs immediately following a rod swap, additional moisture carryover data should be obtained to assure that an increasing trend does not exist. Note that occurrence of steam dryer damage immediately following a rod swap would be highly unlikely.

If the increasing trend of moisture carryover cannot be explained by evaluation of the plant operational data, then initiate plant-specific contingency plans for potential steam dryer damage. If the evaluation of plant data confirms that significant steam dryer damage has most likely occurred, then initiate a plant shutdown.

If there are no statistically significant changes in moisture carryover for an operating cycle, then decreasing the moisture carryover measurement frequency (e.g., from "once per week" to "once per month") may be considered, provided the highest operating power level is not significantly increased.

GE SIL-644, Rev. 1 (Nov. 2004), Appendix D at 32. As noted above, VY Operating Procedure OP 063 1, Appendix F implements this guidance. This monitoring function is to continue for the balance of plant operations.

With respect to inspections, the GE guidelines establish a specific schedule for plants, like VY, that implement a power uprate:

In addition, for plants planning on increasing the operating power level above the OLTP or above the current established uprated power level (i.e., the plant has operated at the current power level for several cycles with no indication of steam dryer integrity issues), the recommendations presented in A (above) should be modified as follows:

B 1. Perform a baseline visual inspection of the steam dryer at the outage prior to initial operation above the OLTP or current power level. Inspection guidelines-for each dryer type are provided in Appendix C.

B2. Repeat the visual inspection of all susceptible locations of the steam dryer during each subsequent refueling outage. Continue the inspections at each refueling outage until at least two full operating cycles at the final uprated power level have been achieved. After two full operating cycles at the final uprated power level, repeat the visual inspection of all susceptible locations of the steam dryer at least once every two refueling outages. For BWR/3-style steam dryers with internal braces in the outer hood, repeat the visual inspection of all susceptible locations of the steam dryer during every refueling outage.

B3. Once structural integrity of any repairs and modifications has been demonstrated and any flaws left "as-is" have been shown to have stabilized at the final uprated power level, longer inspection intervals for these locations may be justified.

GE-SIL-644 at 7.

22. Because VY has a BWR-3 steam dryer, the details of the visual inspection program to be implemented are set forth in the corresponding section of GE SIL-644, which is Appendix C,

p. 15-16. VY is implementing the above described applicable monitoring and visual inspection guidelines in GE-SIL-644.

B. Steam Dryer Monitoring and Inspection During License Renewal Period

23. The aging management program for the VY steam dryer during the twenty-year license renewal period will consist of well-defined monitoring and inspection activities that are defined in the GE SIL-644 guidelines and are identical to those being conducted during the current post-EPU phase. Steam dryer integrity will be monitored continuously via operator monitoring of certain plant parameters. VY Off-normal Procedure ON-3178 alerts the operators that any off the following events could be indicative of reactor internals damage and/or loose parts generation: a) sudden drop in main steam line flow >5%;,b) >3 inch difference in reactor'

.vessel water level instruments; c) sudden drop in steam dome pressure >2 psig. See Exhibit 5 hereto. In addition, periodic measurements of moisture carryover will be performed, and changes in moisture carryover will be evaluated in accordance with the requirements of GE-SIL-644. See Exhibit 3. This monitoring program will continue for the entire license renewal period.

The inspection activities will include visual inspections of the steam dryer every two refueling outages consistent with GE and BWR Vessel Internals Program (VIP) requirements. The inspections will focus on areas that have been repaired, those where flaws exist, and areas that have been susceptible to cracking based on reactor operating experience throughout the industry.

24. The aging management plan for the license renewal period, consisting of the monitoring and inspection activities described above, does not depend on, or use, the CFD and ACM computer codes or the FEM conducted using those codes.

25. License Renewal Application, § 3.1.2.2.11 also commits to "evaluate BWRVIP-139 once it is approved by the staff and either include its recommendations in the VYNPS BWR Vessel Internals Program or inform the staff of VYNPS's exceptions to that document."

BWRVIP-139. is a 2005 industry standard developed by Electric Power Reseaich Institute that provides steam dryer inspection and flaw evaluation guidelines. Those guidelines, Iurrently issued in draft, are essentially the same as the ones contained in the GE SIL standard. BWRVIP-139 is currently under NRC Staff review, with an evaluation scheduled to be released in mid-2007. See http://www.nrc.gov/about-nrc/regulator/licensing/topical-reports/under-review.html#boiling, If the guidelines in BWRVIP-139 are approved by the Staff, Entergy will evaluate any additional requirements that might result from the NRC's approval for applicability to VY. Any commitments made by Entergy will be consistent with the NRC regulatory requirements and guidance for aging management of plant components. VY has made a licensing commitment to "continue inspections in accordance with the Steam Dryer Monitoring Program, Revision 3 [i.e., the current inspection and monitoring program] in the event that the BWRVIP-1 39 is not approved prior to the period of extended operation." VY Licensing Renewal Commitment List, Commitment No. 37, Exhibit 6 hereto.

VI. Response to issues raised by NEC

26. NEC's consultant Dr. Joram Hopenfeld has addressed the steam dryer aging management commitment in the VY License Renewal Application as follows: "The license renewal application states at paragraph 3.1.2.2.11, and Table 3.1.2-2, that the management of cracking in the steam dryer will be in accordance with current guidance per NUREG 1801, GE-SIL-644 and possibly future guidance from BWRVIP-139, if approved by the NRC. No matter which guidance Entergy follows, the status of the existing dryer cracks must be continuously monitored and assessed by a competent engineer." Declaration of Dr. Joram Hopenfeld, dated May 12, 2006 at¶ 19. Entergy's steam dryer aging management plan, however, does exactly.

what Dr. Hopenfeld requires, since it is based on continuous monitoring of plant parameters whose value is indicative of potential dryer cracking and crack propagation.

.27. Dr. Hopenfeld also asserts that "Entergy's monitoring equipment does not measure crack propagation directly (because the strain gages are a distance away from the dryer) and therefore analytical tools would be required to interpret the data." Second Declaration of Joram Hopenfeld, dated June 27, 2006 at ¶ 14, The purpose of the monitoring equipment that was utilized during the EPU power ascension phase (strain gages installed on the main steam lines) was not to measure crack propagation, but to monitor pressure fluctuations in the steam piping that translate to pressure loads and ultimately to stresses on the steam dryer, to ensure that values were below the maximum levels set by the ASME Code. The strain gages will not be used in the aging management program for the steam dryer during the license renewal period.,

28. Dr. Hopenfeld also states that "Entergy has not demonstrated that the dryer will not fail and scatter loose parts in between the visual inspections, especially during design basis accidents, DBA." Id. at ¶ 15. The capability of the dryer to withstand design basis loads was, demonstrated by the structural analyses and stress measurements performed as part of the EPU.

It is important to note that only superficial cracks have been observed in the VY steam dryer and those cracks have not shown any measurable growth in the successive dryer inspections.

Periodic visual examinations of the steam dryer in accordance with the license condition will continue to ensure that unacceptable flaw development or growth is not occurring.

29. Itis also important to note that there are two types of loading imposed on the steam dryer (as well as other plant components.) There are the normal operating loads that are experienced day-in and day-out over the life'of the plant.,These loads are generally lower than the design basis accident loads, but because of the long time duration they can induce fatigue damage. The design basis loads are one-time loads. The purpose of the aging management process is to ensure that the condition of plant components is maintained in a status that is consistent with the design basis analyses for all plant conditions.

30. NEC asserts that "Entergy has previously used these computer models to establish a baseline for its steam dryer management program, and integrated code-based predictions into its aging management assessment. NEC's Contention 3 concerns regarding validity of these models

.are therefore current regardless of whether Entergy will make further use of them." New England Coalition, Inc's Opposition to Entergy's Request for Leave to File Motion for Reconsideration of NEC's Contention 3 (October 12, 2006) at 4. This assertion is incorrect. The purpose of the ACM and CFD analyses was to develop peak loads for the analysis of the steam dryer as a forward looking prediction that no unacceptable fatigue loadings would develop as a the power uprate was being implemented. The plant parameter monitoring and inspection program currently being conducted does not rely on the analyses performed during the implementation of the EPU and is sufficient to ensure satisfactory steam dryer performance during the license renewal period.

VII. Summary and Conclusions

31. My testimony in this Declaration justifies the following conclusions: (1) the steam dryer aging management plan for license renewal period proposed by. Entergy. is consistent with the vendor recommendations and industry guidance; (2) the monitoring and inspection activities called for in the plan are the same that the.NRC has approved for assuring the structural integrity of the steam dryer during current post-EPU operation; and (3) the steam dryer aging management plan will adequately assure that the dryer's structural integrity will be maintained for all plant /

normal and transient operating conditions during the license renewal period.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on April 18, 2007 Jf l l .fnan