ML20046C385
| ML20046C385 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 07/31/1993 |
| From: | Fujikavva K, Ranganath S, Stevens G GENERAL ELECTRIC CO. |
| To: | |
| Shared Package | |
| ML20046C383 | List: |
| References | |
| GE-NE-523-97-07, GE-NE-523-97-0793, GE-NE-523-97-7, GE-NE-523-97-793, NUDOCS 9308100234 | |
| Download: ML20046C385 (71) | |
Text
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{ 1 ENCLOSURE 1 i
BRUNSWICK STEAM ELECTRIC PLANT, UNIT NO.1 ,
NRC DOCKET NO. 50-325 OPERATING LICENSE NO. DPR-71 l CORE SPRAY CRACK ANALYSIS FOR BRUNSWICK UNIT 1 t
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JUL 20 '93 27:26Ft1 GENE ENGRG J2455
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GENE 42347 0732 ;
ClaaeD DM 137 00104 CORE SPRAY CRACK ANALYSIS FOR Brunswick Stearn Electric Plant, Unit 1 July,1993 r
Prepared by: Wh+
G.L. Stsuans, Sanidr Engineer Structural Mechanics Projects N k N eee' K.K. Fujillaha, Senior Eneineer :
Structural Mechanics Projects
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R.H. Booth 4hginser Plant Perifrmance Analysis Projects Verified by:
M.L. Herrera, Principal Enginser Structural Mechanics Projects Approved by:
S. RanganathProjects Manager Structural Mechanics Projects O
GENuclearEnergy
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EER No. 93-0479 t*
Revision No. O GEN 551610!i!2 Rev.O IMPORTANTNOTICEREGARDING CONTENTS OF THIS REPORT Please Road Carefully This report was prepared by General Electric solely for the use of the C Company (CP&U. The information contained in this report is believed by Genera accurate and true representation of the facts known, obtained or pronded to GeneralEl this report was prepared. .
The only undertakings of the General Electric Company respecting informatio are containedin the contract governing CP&L Contract No. 2951DEZZ KB0 93, and no this document shsil be construed as changing said contract. The use of this in defined bysaid contra ct or for anypurpose other than that for which it is intende with respect to anysuch unauthorized use, neither General Electric Companynor a to this document makes any representation or warranty (express or ImpEed) as ,
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accuracy or usefulness of the information contained in this document or that such use o information maynotinfringeprivatelyownedrights;nor do th ey assume any responsibil'ty for liability or damage of anykind which mayresult from such use ofsuch information.
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t c JUL 20 '93 07:27PM GENE,ENGRG JE455 .
EER Wo. 93-0479 Revision No. 0 l GENE 5271015l2 Rev.O I l
TABLE OF CONTENTS i f.EEE d94 '
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- 1. 0 1 N TR O D U C TIO N . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.1 Crack Leaka ge Estim ate ... . . . . . . ... . . . . . . .. ... . . .. .... .. .. ... . ..... .. ... .. ..... . ... . .. . .
1.2 Structural Ana lysis . . . ... . . . . . .. . . . . . . . . .. . . . . . . .. .. . . . . . . . . . . ! .
- 1. 3 Lo s t P art An a ly s i s . . . . . . . . . . . . . . . . . . . . . . . .. ... .... .. 1.-2. . . . . . . . ,
L4 E M %LOCA An alys i s . . . . . . . .. . .. .. .. ... . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . . . . .
- 1. 5 C onclu s iens . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . .
2.0 C RAC K LEAKAG E E STIMATE .. . ... .. . . . .... ..... .. . .. . .. ... . . .. l .
2.1 Current Leakage Rate... .. ... ..... ... .... ... . ..... ... ... ........... .............2-1 ;
2.2 Maximum Estimated Crack Leakage . . ....... .............. ................ ............... 2-2 3.0 CORE SPRAY LINE AND SPARGER STRUCTURAL INTEGRITY.. . ,
3.1 Potential Cause of Cracking and Likelihood of Crack Arrest .. ...... ....... ...... 3-1
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3.1.1 Cracking Mechanism ... .......... ...... . ........ . ...
3.1. 2 Th erm al Fa tig us .. . . . . . . . . . . . . . . . .. . . . . . . ..... .3 .1. .. . ... .. . .$
3.1.3 Intergranular Stress Corrosion Cracking ..... ...... .. .... . . ... ....... . . . . 3-2
- 3. 2 S truct ura l int a g rity . .. . . . .. . .... . . . . . . . . . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . . .
3.2.1 S ummary. . . ...... ...... . .. . .... . . ;
. . . . . . . . . . . . . . ..... . . . . .. . .. . ........ ... 3-3 :
3.2.2 Potential for Crack Arrest..... ..... . ... . . ........ .. . . . .
. . 3-3 !
3.2.3 Core Spray Line Flaw Evaluauen. . . . ... . . .... .. . ... ....... 3-5 -
3.2.3.1 Analysis and Re suits ... ... ..... .......... ....... . .. .... .. . .. ......... 3 6 3.2.3.2 Temperature Gradient Evaluation. .. . . . .. .. .... .... .. .. . . ... . 3-7 (
t 3.2.3.3 Flow induced Vibration Evaluation. ....... ..... . . ........ . .. ..3-8
- 3.3 Sparger Structural Assessment .. .. . ..
.......... . .......... ............ . . . . . . . . 3 -8 3.4 S umma ry a nd C onetusions.... . ... . .... .. .. .. .. ... .... ... .... . . . ... .. . .. .. .. . .. . . ... .... 3-r
- 4. 0 L O ST PARTS AN ALYS IS . .. . ... . . .. . ... . . . .. .. . . . . .. . .. ... . .. .. . +
i 4.1 introduction .... .. ...... . .... ..... .. .
...............................................4-1 1
4.2 Loose Piece Description . ..... ... .... ... . .. .... .... ... . .... ... . .. ....... .... .. .. 4-1 i
- 4. 3 S afety C oncern. .. ... .. ... . . .. . . .. .. . . . . . . .. . . . . .. . ... . . . .. .. . . . .. . . .
- 4. 4 S afety E va t u n tion .. . . .. . . . . . . . . . .. . . . . .. . . .... . .. . .. . .. . .. ... ...4-2. .. . . . . . . .
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- 4. 4.1 General D e serietion . ... . .. ... .... .... . . . . .. . . ... .. .. . . . .. . . ...:
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- !UL 20 *92 27:27DM GEtE ENGRG J2455 EER No. 93-04"79 ' :
Revision No. O {
GEN &52H4?-1LR2Ikv.0 t 4.4.1.1 C ore S pra y P ip e . . . . . . . . . . . . . . . . . . . . . . . .. . .. ... . . ... . . . .. . . . . . . . .
4.4.1.2 Core Spray Sparg er . . ..... . . . . . .. ..... . . .. ...... ..... . . .... ..... 4-2 i 4.4.2 Postulated Leoss Pieces ......... . ......... . ... . .. .... ............... .......... t 4.4.2.1 C ore S pra y Line Pipe .. .. .... .. . . ...... ... . .. . . ..... . . .. .. . . ... .. .. . ... . . 4-3 4.4.2.2 Core Spray Sparger Pipe . .. .. ... ............ . .. ...... .. ..... . . .. ... .. . ...... 4-3 '
4.4.2.3 Loose Pieces From The Core Spray Line ................................ 4-4 4.4.2.4 Loose Pieces From The Core Spray Sparger.......................... 4-5 '
4.4. 2. 5 S pra y N ozzl e . . . . . . . . . .. . . . . . . . . .. .. . . . . . . . . . . . . . .. . . . . . . . . . . . . ... . . . .
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- 4. 5 C onclu slen s. .. .. . . . . . .... .. . . .. . . .. .. ... . .. . ... . ... . .. 4.7 . . . . . ;
5.0 IMPACT O N EC CS ANALYSIS.. ...... . . . ........ . . .. .. ..... . . ....... .. .
5.1 Limiting Break Size and Single Failure Analysis......... ..... ........ . ... . . .. .. .. 5-1 5.2 Impact cf Core Spray Line/Sparger Leak on ECCS Anal
- 5. 3 C onclusie n s .. . .. . . . .. . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . i.
..............................5-3
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- 6. 0 R E F E R E N C E S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 i
APPENDIX A:
STRUCTURAL ANALYSIS OF THE BSEP-1 PLANT' CORE SPRAI A-1: :
S tre s s R e s uits . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . .. . .. . . ,, . . . . . . . . . .
i A-2: Fatigue Craek Growth.... .... ........ .. i
.................................................A-5 :
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JUL 20 '93 07:2 EPM GCE ENGRG J2455
.. - EER No. 93-0479 l Revision No. 0 )
GENES 21-141lB2Rev 0 LISTOF FIGURES Pace No.
Figure 1-1:
Location of B-Loop Core Spray Piping Indication .......... ... ... . ......... .. 1-3 Figure 1-2: Location of B-Loop Core Spray Sparger Indication......... .. .. ...... .... ....1-3 Figure 3-1: Compliance Change in a Cracked Pipe ..................... ..... .. .. . ........... 3-11 Figure 3-2: Cora Spray Line Finite Element Model .......... . .... .. .... .. . .. ... ........ 3-12 Figure 3-3: Stress Distribution in a Cracked Pipe at the Point of Collapse :......: .. 3T3---
Figure 4-1: Loose Piece Potential Upward Flow Path..... .. . ... . .. . . .. ...... .... ......
Figure 4-2: -
R e a ctor As a e mb ly . . . . . . . . . . . . . . . . . . . . . . . .. .4-9 .. . . . . .. .
Figure 4-3: Fuel Assemb!!ss and Control Rod Module. .. ... . .... .... . .... ............. 4-10 Figure 4-4:
S ie a m S e p arator . . . .. . . . . . . .. . . . . . . . .. . . . . .. . . . . . . . . . . . . . .. .. . . . . . ..
Figure 4-5:
Largest Piece That Can Fit Through the Turning Vane (End View).. ... 4-12 LIST OF TdBLES Pace No.
TABLE 3-1:
Resulting Primary Stresses at Core Spray Line Tee Box Region .. .. ... 3-6 TABLE 3-2:
Resulting Primary Stresses at Sparger Tee Box Region .. . . . . . . . . . . 3-9 P
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JUL Ea '93 07:23PM GDE ENGRG JZ455 EER No. 93-0479
.. Revision No. 0 GEN &S&M2-1l82 Rev. 0
1.0 INTRODUCTION
During the current refueling and maintenance outage, the vessel in-service inspe identified crack indications on the B-loop core spray line and sparger at Brunswick Steam Electric Plant, Unit 1 (BSEP-1) as shown in Figures 1-1 and 1-2.
The indications were identified using an underwater camera during the inspection in response to IE Bulletin 8 (Reference 1). The core spray line crack indication is lqcfited outside tha.snroud_in-the affected zone (HAZ) of the circumferential weld located approximately 18" away from piping-tee box junction.
The core spray sparger crack indication is located in the heat affected zone (HAZ) of the circumferential weld joining the lower sparger pipe to the tee inside the shroud.
The following additional information was provided by Carolina Power & Light a)
The core spray line crack is approximately 4 inches in length along the outside diameter of the pipe based on visual measurements.
b)
The core spray sparger crack is approximately 3 inches in length elong th outside diameter of the sparger pipe based on visual measurements.
An evaluation was performed to address the safety signdicance of the through-cracks. The technical basis to support the continued structural integrity of the core and soarger for all ncrmal and injection cenditions is provided. A discussion of the possib consequences of potential loose pieces from a cracked pipe or sparger is also presented. ;
Finally, the consequences of a postulated Loss of Coolant Accident (LOCA) with crack core spray piping and sparger are discussed.
i 1.1 Crack Leakage Eatimate A bounding calculation to estimate the leakage through the cracks, presented in Section 2, demonstrates that the total leakage is well within the margin inherent in the co spray system design and performance evaluations. The results indicate that for this two-crack configuration, including the postulated crack growth over the next operating cycle, the t flow leakage is conservatively estimated to be approximately 50 gallons per minuts 1-1
JUL 2d '93 67:E9PM GENE ENGRG J2455 EER No. 93-0479
, Revision No. 0 GEN &5?M G152 & O 1.2 Structural Analysis The structural analysis, presented in Section 3, concludes that the integrity of the spray pipe and sparger will be maintained for all conditions of operation over the next operating cycle (assumed to be 12,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of hot cperation). In addition, potential causes of cracking are discussed.
Based on the information available, it is expected that the most dominant mechanism is intergranular Stress Corrosion Cracking (IGSCC).
1.3 Lost Part;Anahsisu -c -
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Because continued core spray pipe and sparger structural Integrity ware demons lost parts (loose pieces) are not expected. Nevertheless, a lost parts analysis has been performed and is presented in Section 4.
It is concluded that the probability of unacceptable flow blockage of a fuel assembly or unacceptable control rod interference due to lo negligible. The potential for corrosion or other chemical reactions with reactor materials d not exist because the piping and sparger materials.are designed for in-vessel use. It is also shown that loose pieces are not expected to cause damage to the other reactor pres vessel (RPV) internals.
1.4 Effect on LOCA Analysis Section 5 presents the results cf the LOCA analysis. The results show that the inherent conservatism present in current LOCA analyses more than offset the small amou leakage estimated through the two cracks.
It is concluded that no change to the present !
Maximum Average Plant Linear Heat Generation Rate (MAPLHGR) for BSEP-1 is requi l l
l 1.5 Conclusions i Detailed evaluations of the BSEP-1 core spray line and sparger cracks have been performed. This evaluation included structural, lost parts and LOCA analyses to determin the impact on plant operation with the cracks in the core spray piping and sparger. Based on the analysis, it is concluded that BSEP-1 can safely operate in this condition during the ne i fuel cycle, and that no operational changes or restrictions are required during that period I
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'JUL 20 ' '93 ' 07:29PM GENE ENGRG J2455 EER No. 93-0479
,. Revision No. 0 '
GE M .93161LB2&W0 ,
Figure 1-1: Location of B-Loop Core Spray Piping indication i
i 270* RPV Azimuth 3 0*-290" >
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[ B-Loop Core Spray 1 '
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) y Weld Figure 1-2: Location of B Loop Core Spray SpargerIndication -
ass' RPV Azimuth Mow Nozzle
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~3" Long Indication [ )
in Weld HAZ 1 . . . , --
, JUL 20 '93 07:29PM GEtE ENGRG J2455 EER No. 93*efl9 5
' Revision No. 0 l
GENES 21-!<2-15tzlhv 0 2.0 CRACK LEAKAGE ESTIMATE ~
l There are no direct measurements of leakage from the pipe or sparger crac operation of the core spray system. However, from previous analyses and tests performed the cracks observed in other boiling water reactors (BWRs), it is possible to establish an upper bound leakage for the cracks identified at BSEP-1.
The significance of previous crack occurrences at other BWRs has beert ass both visual Inspections and air-bubb!(iests. ' Based upon these inspections and: test upper bound leakage was estimated to be less than half the leakage through the 1/4-!nch vent hole present in the T-box. The vent hole is part of the original piping design, and is includ to allow the release of any non-condensables which could collect in the core spra The visual inspection for BSEP-1 indicated that the crack in the core spray line is estim be 4 inches in length. A conservative approachJs.t9 assume a 180* through well crack an estimate the bounding leakage rate.- Cons,aryative
- analyses show the maximurn this assumption, from the core spray line cra'ch is approximately 8 GPM, for ad8 through-wall crack. Similarly, the visual ir}spection for BSEP-1 Indicated that the crack in core spray sparger is estimated to be 31nches in length. The maximum leakage from the core spray sparger crack is approximately 3 GPM, for a'180* through-wall crack (=S.9").
2.1 Current Leakage Rate There are two sources of leakage present in the current (uneracked) BSEP-1 core spray configuration:
(1) leakage through the 1/4-inch vent hole in the toe box located at the core spray nozzle entrance to the vessel, and (2) leakage through the clearance between the core spray nozzle safe end and thermal sleeve. Each of these leakager flows are conservatively estimated below.
i The vent hole is a 1/4-inch hole present in the tee box. The leakage rate through vent hole is estimated assuming incompressible Bernoulli flow through the hole: -
1 O = CA42g,$ pip where:
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JUL 22 '93 27:20PM GENE ENGRG J2455 EER No. 33-0479
.- Revision No. 0 GENES 2714712tB Av.O C = flow coefficient (assumed to be 0.8 for an abrupt contraction)
A = area of opening .
i p = mass density of fluid at temperature aP = pressure difference across the pipe / vent The flow rate through the vent hole was determined using a bounding pressure of l 70 psig (Reference 2) across the core spray line. Using the equation above, the estimated leakage rate through the vent hole during a LOCA was determined to be less than 10 GPM.
j Based on prior inspections and tests during the core. spray injection phase of a LOCA, the l
current leakage through the core spray line crack is expected to be less than 5 GPM (less '
than one-half of the vent hole leakage).
The flow rate through the thermal sleeve-safe end clearance was also determined using a bounding pressure of 70 psig (Reference 2) across the thermal sleeve. Again usi the above equation, the estimated leak rate through the thermal sleeve clearance, using maximum radial clearance of 0.008" between, thermal sleeve and safe end (Reference 3),
caring a LOCA was determined to be approximately 30 GPM.
w 7 2 Maximum Estimated Crack Leakage .
In order to estimate the maximum leakage expected through each crack. the !
configurations for 180* through wall cracks were used. This configuration was considered to i
te the upper bound based on the crack arrest results of Section 3. A crack width of 0.01 Inch was conservatively assumed based on the results of Linear Elastic Fracture Mechanics (LEFM) methods which showed the crack opening for both cracks to be < 0.01 inch under the applied loads described in Section 3.
Using the methods of Section 3.2 for the applied loads and the 180' through-wall crack configurations, the leakage was determined to be approximately 8 GPM for the core spray lin crack and approximately 3 GPM for the sparger crack.
1 It was also estimated that both the core spray line crack size and the sparger crack size are expected to grow less than 1.2 inches and 1.1 inches, respectively, during the next 18 month cycle (core spray line total crack length = 5.2 inches and sparger crack length =
4.1 inches). The result for the core spray line is based on the consideration of both IGSCC I
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. JUL Ea 'o3 27:20PM GENE ENGRG JE455 s
EER No. 93-0479 ,
. Revision No. O i GENEM142 flBERev.O and fatigue crack growth, and for the sparger is based on lGSCC considerations only. Forj IGSCC, conservative crack growth rates at moderate conductivity for 304 stainless steel were1 assumed (4x104 inch / hour), and crack growth from both ends of the cracks were considered.
The assumed IGSCC crack growth rate is considered conservative for two reasons:
- 1) The assumed value of crack growth is based on normal water chemistry conditions Although the electrochemical potential (ECP) in the area of the core spray line is n expected to meet the necessary level for full IGSCC protection, the crack growth '
rate is likely to be substantially lower than the assumed value of 4x104 inch / hour.
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- 2) Using the NRC crack growth curve (Reference 4), the assumed crack growth rate of
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4x10-5 inch / hour is predicted at a stress intensity factor, K, of 25 kskinch. Since l
the subject crack is through-wall. (thus, the weld residual stress Induced. K is expected to be very low), and the applied stresses-are low, the K values are expected to be less than 25 ksidinch .for realistic crack geometries.
a *;, ,
Thus, even after 18 months of additional operation, the crack lengths are eW to be less l
~ than 125* of the pipe circumference. Therefore, the leakage estimates of 8 GPM and 3 GPM for the ccre spray line and sparger cracks for 180" crack lengths are conservative for the next cycle.
2-3
JUL 22 '93 27:31PM GENE ENGRG J2455 EER No. 93-0479 Revision No. 0 GE-NES271G10R2 Rw.0 3.0 CORE SPRAY LINE AND SPARGER STRUCTURAL INTEGRITY The structural integrity aspects of the core spray piping and sparger wore reviewed to assess:
a) the potential cracking mechanism, and b) the impact the crack could have on the structural integrity of the piping. Previous structural analyses (References 5 and 6) coupled with new, additional analyses were utilized to determine the potential sources of stress in the piping and sparger. the potential causes of cracking, and the likelthood of crack propagation.
Although there is currently not enough information to definitively determine the mode of cracking, it is expected that the crack is due to an intergranular stress corrosion cracking (IGSCC) mechanism. Irradiation Assisted Stress Corrosion Cracking (IASCC) is not expected to be a significant contributor to core spray line cracking sines the fluence in the annulus is expected to be below the IASCC. threshold. The fluence may be higher for the sparger, but since it is located above the top of the fuel, the cummulative fluence is still likely to be below
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the IASCC threshold. The . e::ults of these',assessments are discussed below.
3.1 Potential Cause of Cracking and Likellhood of Crack Arrest 3.1.1 Cracking Mechanism Cracks in the core spray line and sparger could be due to either thermal fatigue or IGSCC. Previous experience confirms the absence of flow induced viration (Section 3.2.3.3).
Therefore. fatigue oue to vibration is not considereo to be a contributor to the cracking. At this point, there is not enough information to cetermine the mode of cracking, definitively.
Consequently, the following discussion addresses the implications of the observed cracking assuming each meenanism separately.
3.1.2 Thermal Fatigue Core Scrav Line The feedwater sparger is located above the cere spray piping in the annulus. Some high frequency thermal cycling could occur near the core spray piping because of the turbulent mixing of the cooler feedwater from the feedwater sparger and the hotter downcomer flow. The magnitude of temperature cycling is dependent on the feedwater temperature and 3-1
- JUL 22 '93 27:21FM GENE E.NGRG JE455 EER No. 93-0479 !
Revision No. O !
GE-NMB 1410% Rw.0 flow rate. Fatigue initiation cue to thermal cycling is not only a function of th !
cifference between the feedwater ano downcomer flow, but also depends on th over which the cycling occurs. With this cyclic mechanism, crack initiation is m occur near a weld because of the high residual stresses present. Even if fatigue initiat does occur because of rapid thermal cycling, the cracking is likely to be confined to cutside surface of the pipe since the thermal stresses attenuate rapidly through th cf the pipe. Thus, if thermal fatigue is the initiation mechanism, extensive fat is unlikely (further growth can occur by IGSCC since the fatigue crack acts ,
Therefore, the IGSCC induced growth analysis desenbed below is a boundin assessment as shown later in this section. [
Sparcer No enving forces for a thermal fatigue mechanism have been identified f region. The Reference 5 study concluded that only 8"F temperature variations exis area cf the RPV during operation and concluded that crack initiation as a result of the fatigue was not likely.
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3.1.3 Intergranular Stress Corrosion Cracking Core Scrav Line The core spray line in BSEP-1 wnere the crack is located is made of type 304 s steel. Type 304 stainless steel can sensitize, ieacing to IGSCC in the weld HAZ. Loc work which could have occurred during fabrication can also contribute to IGSCC Initi The electrochemical potential (ECP) at the core spray line is expected to ce high cbserved cracking is of IGSCC origin, some crack growth during future operation ca ruled out.
A conservative estimate of this potential crack growth and its effect on the structural integrity of the cere .
T. line is discussed in Section 3.2. t Scarcer The Reference 5 report provided extensive discussion of the probable cause oI cracking in the core spray sparger. In that report, the potential metallurgical causes spray sparger cracking were diviced into those relevant to cracking in the heat affected zo (HAZ) cf the T-box to sparger arm weid, as well as those related to cracking 3-2
, JUL Ea '92 27:2 EPM GD'E DGG J2455
+
EER No. 93-0479
.- Revision No. 0 GENES 516152 Rev.O arm remote from the weld. The most probable cause of cracking for the region in the heat-affected zone was identified as cold work and subsequent sensitization. As with the core spray line region, if the observed cracking is of IGSCC origin, some crack growth during future operation can not be ruled out. A conservative estimate of this potential crack growth and its effect on the structural integrity of the sparger is discussed in Section 3.2.
3.2 Structuralintegrity 3.2.1 Summary '
All identified stresses expected during normal reactor operation were found to be small.
Based upon a review of these Mresses, it is concluded that the structural integrity of the anc sparger with the cracks will be maiatained during core spray injection. The stresses considered include those due to cowncomer ficw impingement loads, seismic loading, pressure, weight and thermally induced leads.
Although the normal operating loads by themselves do not result in stresses which are sufficient to cause IGSCC Initiation, the addition of the weld residual stresses coupled with local cold work could result in exceeding the initiation threshold. Once initiated, the normal operating load stresses and the residual stresses could cause subsequent growth of the induced cracks.
In order to determine the integaty of the core spray line and spr,rger with cracks press. t, crack arrest evaluations were performed. The stresses due to pipe restraint were also inc.:'ded in these evaluations. Because the applied normal loading for both components are predominantly displacement controlled, the stresses relax as the cracks grow and the compliance (or flexibility) of the pipe or sparger increase. The results of the analyses show that wnen the cracks reach 180' cf the circumference, the compliance is reduced sufficie to relieve almost all of the cisplacement controlled stresses. Consequently, the crack growth is expected to be negligible or at virtual arrest prior to reaching 180' The current extent of cracking for both components is less than 90' of the pipe circumference.
3-3
, 20 22 '91 27:IE:M GENE ENG;G 12455 EER No. 93-0479
.+ Revision No. v GENEMIG1W2 Rev.O 3.2.2 Potential for Crack Arrest
_ Core Soray Line Stresses in tne core spray line due to bracxet restraint are governed by the displacement and the compliance of the pipe. Since the displacement is fixed, the change with erack growth could lead to virtual crack arrest. This is comparable to crack in a bo!t loaded wedge-opening loading (WOL) specimen in stress corrosion tests.
Figure 3-1 shows the variation of ecmpliance with crack length for a pipe subje bending.
The compliance was determined using the relationship between strain e release rate, G, ano the compliance change per unit area of crack extension, de/dA (Reference 7). For tne cracks in the ccre spray line. UD is expected to be in the r 1 UD < 40. Figure 3-1 snows that the compliance of the pipe increases by a factor of ten '
more than 30% of the pipe is cracked. Therefore, for the given initial displacement, the st -
in the core spray line and the applied stress intensity factor would decrease by a fact when more than 30% of the pipe circumference is cracked. Clearly, when the c exceeds this value, the restraint stresses become negligible and crack arrest is expec Therefore, crack arrest or small growth rate is expected before the crack grows to 180' Scercer In assessing the possioility of scarger crack arrest. the following sources of stress we consicered in the Reference 5 stucy:
1.
Stress oue to pressure, meenanical loao and thermal gradients. These stresses were shown to be negligible and were not considered in the crack growth assessment.
2.
Stresses due to bracket restraint: These are displacement controlleo (secondary) stresses ano are expectee to relax as the crack propagates.
3.
Residual stress due to fabrication: As the crack propagates into a region of compression, the stress intensity facter can be expected to decrease, thereoy resutting in possiele arrest.
3-4
6 JUL 22 '92 27'2 EPM GENE ENGRG !Z455 EER No. 93-0479 ;
.* Revision No. O !
GENE 573-142152. Rev. 0 4
Weld residual stress: Weld residual stresses at the T-box-sparger welds would influence crack propagation. These stresses are likely to vary circumferentially '
and also relax as the cracks become larger. Fluence has the effect of relaxing the residual stresses.
5.
Stresses due to vibration were assumed to be negligible.
6.
The stresses due to bracket restraint and the fabrication residual stre determined to be significant and were evaluated In detail.
Based on the above material, the following conclusions were drawn:
1.
Since the acplied leading is preocminantly disolacement centrolled, the stresses are expected to relax as the crack grows. Crack arrest er small growth is therefore likely.
- 2. i The residual stresses due to fabrication were determined to vary from tension to l
~
compression. As the crack propagates into regions of compressive stress, the K value reduces to zero. Even for extremely conservative assumptions, virtual crack arrest can be shown for a 50% circumferential crack.
i
- 3. ;
The above conclusions are valid as long as there is not stress cycling due to !
vibration (e.g., flow-induced vibration-FlV). However, as discussed in Section l
3.2.3.3, FlV stresses are small.
3.2.3 Core Spray Line Flaw Evaluation !
l i
Even thougn the cracks are expected to be in a state of virtual arrest at 180' under the sustained displacement controlled loading as discussed in Section 3.2.2, an evaluation was performed to determine the maximum circumferential through-wall flaw size in the core s line. This analysis will therefore provide an assessment of the safety margin in the line due to primary loads suen as ceadweight, pressure, flow impingement and seismic.
The acceptable through-wall flaw size of the core spray line is determined utilizing th not section collapse formulation of Reference 8.
To apply this methodology, primary membrane stresses in the longitudinal direction and primary bending stress 6s were 35 !
!;.:L ED '92 27:22PM GENE ENGRG JE455
. EER No. 9 3 - 04 ~7 9
. Revision No. 0 GENE 573-142-152 Rev. 0 determined for the T-box region of the pipe. A finite element model of the core spray line developed to obtain the stresses due to deacweight, seismic and RPV downcomer flow impingement on the pipe at the location of interest. The resulting stresses were then '
ccmcined with the stresses due to pressure and core spray flow loads in order to get the stresses acting on the pipe.
Stresses due to water hammer leads were considered insignificant and neglected in this analysis. This is based on the fact that core spray inlet valves typically ramp open ove e period cf several seconds upon system actuation. Additionally, the piping is full of water during actuation because of the presence of the vent hole on the top of the T-box. Previous analyses have shown that the water hammer loads in the cere spray line are less than 20 pounds of axialload on the pipe.
Finally, stresses cue to thermal mismatch were evaluated and found to be insignifica Therefore, by applying the resulting primary stresses, it was shown that the core spra can tolerate a crack up to 240' througn-wall at the T-box location without incipient failure.
3.2.3.1 Analysis and Results A finite element model of the ccre spray line configuration was constructed using th ANSYS computer coes (Reference 9). A sketch of the finite element model is shown in Figure 3-2. The following boundary conditions were applied to the model:
Nodes 1, 49, 53: ccmpletely fixeo Nodes 13,37 fixed in vessel radial direction to account for bolted vessel clamps.
Loads due to the weight of the pipe (inc!ucing captured water in the pipe) were ap to the model along with vertical and horizontal seismic loads and RPV downcomer flow impingement loads.
Calculations cf these loacs are given in Appendix A. The largest resulting stresses in the region of the T-box (nodes 23-27) were used from the finite elemen '
model results. These stresses were then combined with the stresses due to pressure and ccre spray flow loaos. The resulting total stresses are shown in Table 3-1.
Note that loads due to thermal mismatch of the core spray line and RPV need not be included as they secondary in nature.
l 3-6
, JuL E2 '92 27:24PM GENE ENGRG J2455 i 4
EER No 93-0479 !
.' Revision No. ?
G&NES21-147-trB2 Rev.O TABLE 3-1: Resulting Primary Stresses at Core Spray Line Tee Box Region Membrane Stress, P m 670 psi '
Bending Stress, P 3 2,233 psi The stresses of Table 3-1 are utilized to determine the acceptable through-wall flaw size based on the methods of Reference 8. The critical flaw size is determined by using limit Icad concepts. It is assumed that the pipe with a circumferential crack is at the point of incipient failure when the net section at the crack develops a plastic hinge. Plastic flow is assumed to occur at a critical stress level, ef, called the flow stress of the material. For ASME Code analysis, er may be taken as equivalent to 3Sm. This results in considerable simplification of the analysis. '
Consider a circumferential crack of length, ! = 2Ra, and constraint depth, d, located as shown in Figure 3-3. In order to determine the point at which collapse occurs, it is necessary to apply the equations of equilibrium assuming tnat the cracked section behaves like a hinge
~
For this condition, the assumed stress state at the cracked section is as shown in Figure 3-3 1 where the maximum stress is the flow stress of the material, cf. Equilibrium of longitudinal forces and moments about the axis gives the following equations:
For neutral axis located such that a + S < :-
S = ((= - ad/t) - (Pm/of):}/2 P3 = (2c/ )(2 sin S - c/t sin c) where: t = pipe thickness, inches.
a = crack half-angle as shown in Figure 3-3.
S = angle tnat defines the location cf the neutral axis.
Using tne stresses cf Table 3-1 and a d/t ratio cf 1.0 (through-wall flaw), the through-wall crack for which failure oy collapse might occur is 240*.
3-7
, Ju_ 20 '93 F: IGM IENE ENGRG JE455 EER No. 93-0479
.* Revision No. 0 GENE 55142-152 kv.0 3.2.3.2 Temperature Gradient Evaluation A fatigue crack growth analysis due to thermal gradients across the core spray piping was concueted using conservative values for the temperature differences expected between the inside and outside surfaces of the core spray pipe. Two events were conservatively considerec for this analysir. The first was a HPCI injection in which cold water (100'F) from the feedwater soargers irNngos on the hot core spray line (550*F). Conservatively assuming the temperature at the
- tt a of the core spray piping remains at 550'F, a thermal bencing stress results across the pipe cross section. The second event considered was the actuation cf the ccre spray system. In this event, cold water (50*F) is injected through the het core spray line (550*F) which irduces a uniform thermal membrane stress throughout the pipe cross section. This analysis showed that a conservative estimate of the fatigue crack growth cue to HPCI and core scray injections is about 0.33 inches. Details of this analysis are provided in Appendix A. This growth is minimal when compared to the crack growth precictec cue to the IGSCC mechanism (predicted to be 0.96 inches). Based on this conservative evaluation, fatigue crack propagation as a result of severe thermal transients is negligible when compared to that frem IGSCC.
3.2.3.3 Flowinduced Vibration Evaluation A flow incuted vibration (FIV) evaluatien was concucted censidering field measurea data from a similarly deQned core spray system. In creer to eliminate FIV concerns. it is required that the naturai "requency cf the system ce greater than three times the vonex sneddng frecuency. The vortex snecding frecuency for this system cue to cowncemer flow was calculated to be 5.1 Hz. A natural frequency of 27.5 Hz was octained for the core spray line from the limited field data. To assess the potential change in these values as a result of a cracked core spray line, additional analysis was conducted assuming a 180' thrcugn-wall crack. The ratio of the ecmpliance of the uncracked line to the cracked line was calculated to be 0.649. Given that the natural frequency is propertional to the square root of the stiffness (stiffness = inverse of the compliance), this leade to a predicted 20% decrease in the natural frequency (22 Hz). Since this adjusted value of the natural frecuency still remains greater than three times the vortex sneeding frequency (15.2 Hz). the results of this evaluation show that no degracation as a result of FIV is expected.
3-8
, JUL Ea '93 27:IEFM GENE DGs ;I455 EER No. 93-0479
. Revis10:. No. D I GEN 555101W2 Rev. 0 3.3 Sparger Structural Assessment i
Even thougn a 360* througn-wall crack is improbable, a structural analysis was performed in Reference 5 for the soarger which conservatively assumed that a crack located in the heat-affected zone cf the sparger to T-box weld had propagated 360' through-wall.
Leads which were considered incluced all loacs applicable to the intact sparger. The analysis ignoreo the effect cf a ciamp (or assumed a clamp was not installed).
Stresses during normal operation and during core spray injection were found to be well below allowables.
The natural frecuency of the assumed broken sparger remains high enougn so that flow-incuced vibration is not a concern. It was concluded that the sparger would lose no pieces and would remain attaened to the shroud wail under the conservative assumption that an assumed crack crecagates 360* througn-wall.
i The stresses calculated in Reference 5 are summarized in Table 3-2. Using these stresses and a d/t ratio of 1.0 (through-wall flaw), the through-wall crack for which failure by ecllapse might occur is approximately 220'
' 1 TABLE 3-2: Resulting Primary Stresses at Sparger Tee Box Region Membrane Stress, P m 3,540 psi l
(includes some thermal stresses)
Bending Stress. P 5S8 osi
{
1 3.4 Summary and Conclusions The potential sources of stress in the core spray line ano sparger resulting from normal operation and operatien curing postulated LOCAs were reviewed. Potential causes of cracking, thermal fatigue and 1GSCC, and the likelihood cf crack propagation were also evaluated. It is excected that the cracks were caused by IGSCC.
Because of the predominant seconcary stresses, the cracks can be expected to be at er near arrest prior to reacning 180* Assessment were made to determine the critical flaw 3-9 l
20L 23 '93 27: 35FM GD4E ENG G 23455 EER No. 93-0479 !
Revision No. 0 l GEN &573-142-1W2 Rev. O sizes of the ccre spray line and sparger by treating stresses associated with the desig loading as primary stresses and performing net section collapse evaluations. The results of these evaluations ccnfirm that a througn-wall crack of up to 240* around the circumference would not cause cere spray line failure, or a crack cf up to 220* around the circumference would not cause sparger failure. These lengths are much greater than the maximum estimated crack lengins at the end of the next fuel cycle (predicted to be 5.2 inches for the ccre spray line and 4.1 Inenes for the sparger). Therefore, it is concluded that the structural integrity of the core spray line and sparger with cracks will be maintained for all conditions of normal cperation for the next operating cycle.
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3-10
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- ' i Rev. 10/91 UNIT 0 Ret: Life of attachments RMP-007
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PART B The attached record is the most legible copy available and may be retained in the RFR,
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Records Receipt 0 RMP-007 Rev. 9 Page 21 of 24 l
JUL 23 '93 07:IEP!1 GDE D4GRG J2455 EER No. 93-0479 Revision No. 0 GENE 573101al2 Rw.0 1 Figure 31: Compliance Change in a Cracked Pipe t0.000 s
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, 21 23 '93 27:IE::!1 GENE ENG:iG JZ.:55 EER No. 93-04~9 '
- Revision No. J i
GEN 555142-1LE2 Rev.0 i
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Figure 3 3: Stress Distribution in a Cracked Pipe at the Point of Collapse I
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i 3-13 '
EER No. 93-0479 1
Revision No. O GENEM101022 Rev.0 4.0 LOST PARTS ANALYSIS 4.1 Introduction Based on the structural analysis given in Section 3, it is 6xpected that the BS spray line pipe and core spray sparger will not break and consequently, will not re pieces in the reactor. However, an evaluation of the possible consequenr*.s of loose piece is presented in this section.
4.2 Loose Piece Description Since a piece has not been lost. it cannet be uniquely described. Two differ loose p!eces are postulated for the core spray line:
- 1) a section of core spray pipe; and
- 2) a small piece of the core spray pipe.
Three different types of loose pieces are postulated for the core spray sparger
- 1) a section of sparger pipe;
- 2) a small piece of the sparger; and
- 3) an outlet nozzle.
4.3 Safety Concern The following safety concerns are addressed in this safety analysis: !
1)
Potential for corrosion or other chemical reaction to reactor mate 2)
Potential for fuel bundle flow blockage and subsequent fuel damage.
- 3) Potential for interference with control rod operation.
- 4) Potential for damage to cther reacter internals.
4-1 S2*d
+
+
EER No. 93-0479
. Revision No. 0 GEN &551#1mzRev.O 4,4 Safety Evaluation The above safety concerns for the postulated locse pieces are addressed in this section. The effect of these concerns on safe reactor operation is also addressed.
4.4.1 General Description 4.4.1.1 Core Spray Pipe Since the core spray pipe crack is in the Ennular region of the RPV, this evaluatio assumes that any potential loose piece generated from the core spray pipe will mos sink into the downcomer region.
l For a loose part to reach and potentially block the inlet cf a fuel assembly (Fig '
it would have to be carried into the lower plenum. To accomplish this, it would have to b carried by the recirculation flow through the jet pump nozzle into the lower plenum, then ml
_ a 180* turn and be carried upward to the fuel assembly inlet orifices.
For a piece of the core spray pipe to reach a control rod it must first migrate to the lower plenum, pass through the fuel inlet orifice, and traverse the fuel bundle. Then, it mus either fall through the restrictive passage between two fuel channels, or fall through an opening between the peripheral buncles and the core shroud. Both cf these potential pai are untikely.
The core spray pipe is fabricated from Type-304 grade stainless steel and all parts the core spray pipe are designed for in-reactor s'ervice. Consequently, there is no postulated loose part that will cause any corrosion or othe~ chemical reaction with any reactor material.
4.4.1.2 Core Spray Sparger The core spray spargers are attached to the inside of the core shroud (Figure 4-2) the upper plenum. For a piece of the sparger to reach and potentially block the inlet of a fuel assembly, it would have to be carried out of the upper plenum and pass down into the lower plenum. To accomplish this, it would have to be carried by the fit.'o flow in the upper plenum 4-2 92'd
EER No. 93-0479 Revision No. 0 GENE 52116IW2 Ex 0 up through the steam separators then outward to the downcomer annulus, then pump nozzle into the lower plenum, then make a 180' turn and be carried upward to th assembly inlet orifices. A part of the sparger cannot reach the fuel assembly falling down inside the core shroud because the core support plate and the load prevent this. For a part of the core spray sparger to reach a control rod, it must first tra the upper plenum from the outer region cf the shroud toward the center, then either fa through the rostrictive passage between two fuel channels, or fall through an o between the outside cf the peripheral bundles and the core shroud, both of whic Since all parts cf the core spray sparger are designed for in-reactor service, the possibility that any loose part will cause any corrosion or other chemical reacti reactor material.
4.4.2 Postulated Loose Pieces !
4.4.2.1 Core Spray Line Pipe !
The core spray pipe is 5 inch, schedule 40 pipe. In order to generate a loose p pipe, a minimum of two through-wall cracks would have to propagate 360* around If a pipe segment were postulated to break off, it would sink into the downcomer Since it cannot fit through the jet cump. it cannot enter the icwer planum, and therefore w cause any flow blockage at the fuel inlet enfice. Since it is too large to fit between fuel cnannets, it cannot cause any interference with control red operations. Due to the slow propagation rate of potential cracks, and based on previous experience with cracks in the core spray line. it is judged that a piece of the piping will not break off and become loose in the reactor.
4.4.2.2 Core Spray Sparger Pipe The sparger pipe is 3.5-inch, senedule 40 pipe and is attached to the core shroud at seven locations (T-box plus six brackets). In order to generate a loose piece of pipe, a minimum of two through-wall cracks would have to propagate 360* around the sparger. Th weight of the largest pipe segment would be approximately 84 lb. (Reference 5). Because of the slow rate of potential cracks to propagate, and based on previous experience with cracks '
4-3 d'd
EER No. 93-0479 Revisicn No. 0 GE NE5 5 1 0 15Cz Rev.0 in core spray spargers, it is judged that pieces will not break cff and become lo reactor.
A pipe segment could come to rest in any of three locations: (1) the top surface of the top guide outboard of the fuel assemblies; (2) the top surface of the fuel assem (3)in an unlikely event, the top surface of the core plate. In all three of these locat ,
flow velocity (Reference 5) is low and insufficient to lift a segment of the pipe. T ,
will remain at one of these locations and is not expected to lift or rattle aroun of pipe which falls from the core spray sparger will not harm the core plate, top assemoly handles, since these components are designed for much larger loads.
Since the pipe cannot be hfted by the flow (Reference 5), and since the pip througn either the steam separater er the jet pump, it will not cause any flow block fuel inlet orifice. Since the pipe is too large to fit between fuel channels, it wi interference with control rod operations.
4.4.2.3 Loose Pieces From The Core Spray Line In creer to generate small pieces cf the core spray pipe, both longitudinal and circumferential through. wall cracking must occur. A small piece could then sink, be ca into the downecmer annulus, pass through the jet pump and enter the lower plenum that entered the lower plenum would probably be oriven by the jet pump flow to the botto the RPV where it would be expected to remain. However, a small piece 5 0.4 inches co camed by the ficw up to the fuel in!st crifices.
The enfice sizes in BSEP-1 vary from approximately 1.2 to 2.5 inches in diameter.
Given the cimensions, the piece would pass through the inlet orifices and be tra the lower tie plate grid and cause some buncle flow blockage. However, the flow blo much less than that required to initiate critical boiling transition in the bundle. Multiple p migrating to the same bundle may result in critical flow blockage, but the probability for suc an occurrence is extremely low.
It is also very unlikely that a small piece could lift and migrate from the lower plenum through the fuel bundle and fall into the centrol rod guide tube. In order to do this, the pie would have to be so small that it could pass through all the bundle spacers and out th 4-4 Ba'd
l EER No. 93-0479 j Revision No. 0 G&N5!i&101022 Rev.O the top of the bundle.
Such a small piece would not present any potential for control rod t interference.
Figure 4-3 show a typical unit cell of four fuel assemblies and one control rod. T i
control rod moves in the gap betwean the fuel channels. There is a small possibility piece small enough to fit in the gap between the channel wall and control blade couldi pass though the cavity between the control blade and the fuel support casting an into the control rod guide tube. Should this happen the piece will most likely come tol the top of the velocity limiter where it is expected to remain and move only with the mo of the velocity limiter as the control rod is inserted or withdrawn. If the piece is s to pass between the velocity limiter and the guide tube wall it will most likely sink and co i
rest at the bottom of the guide tube. Due to the harcware geometry of the control blade dr mechanism it is highly unlikely that any piece would be small enough to migrate into the control blade drive system. Thus, any potential small piece wnich migrates to the control ro guide tube is not expected to pose any concem for potential interference with control rod operation.
One of the licensing bases of the reactor is that with the highest worth contr withdrawn the reactor can be brought to cold shutdown. Thus, unacceptable control rod interference would require multiple precisaly sized pieces interfering simultaneousl control rods that are in close proximity to each other. The probability of this is judged to be insignificant (Reference 6).
4.4.2.4 Loose Places From The Core Spray Sparger in order to generate small pieces of the sparger, both longitudinal and circumferential through-wall cracking must occur. A small piece could be lifted by the flow if it maintained a orientation with its maximum projected area perpendicular to the flow. Due to flow turbulence ano non-symmetry of the loose piece, the piece will tend to rotate so that the minimum l
projected area will be perpendicular to the flow. With this orientation and based on the '
velocities in the upper and lower pienum, all parts in the upper plenum with a length of than approximately 0.4 inch and in the lower plenum with a length of greater than approximately 1.4 inches will sink. Thus, most pieces will not be carried by the flow toward l
the steam separator. However, in the unlikely event that a piece reaches the steam sep it would have to pass through the steam separator turning vane (Figure 4-4). There a curved vanes with the outlet of each vane overlapping the inlet of the adjacent vane. The 4-5 sa'd .
EER No. 93-0479 Revision No. O GENS 521-1&1022 Rev.O longest straight piece that can fit through the turning vane is approximately 6 inc it must be oriented with the long dimension in the vertical oirection. The largest piec fit through the turning vane is shown in Figure 4-5 and is approximately 6 x 2 x 2 i flow velocit!ss are Insufficient to carry this size piece through the turning vane (
After passing through the tuming vane, thw fluid momentum is further reduced as water is removed. At the separator exit, the fluid is almost entirely steam. A typical w centent is 1 weight percent. Thus, it is very unlikely that any piece could be carried out o separator by the steam. If any piece were carried through the separator by the steam, t could be carried into the downcomer annulus, through the jet pump and enter the lower plenum. A piece that entered the lower plenum would probably be driven by the jet to the bottom of the RPV where it would be expected to remain. However, a smal incnes could be carried by the flew up to the flow inlet enfices. The enfice sizes in BSEP-1 vary from approximately 1.2 to 2.5 inches in diameter.
It is extremely unlikely for a piece larger than the 1.2 inch orifice and essen impossible for a piece larger than the 2.5 inch orifice to be carried through the steam separator.
Unacceptable flow blockage would require that more than one loose piece be carried to the same inlet orifice. This is based on the size of the piece (s) that, in a unlikely circumstance, have the potential of reaching the vessel lower plenum. Unacce flow blockage of any fuel onfice requires multiple pieces at the same orifica, and the probability of several pieces blocking a significant portion of the bundle inlet to cause significant fuel damage is judged to be essentially zero.
The flow velocities near the sparger are lower than those above the fuel asserr.blie Thus, it is unlikely that a small piece would be carried over the fuel assemblies (Rej if the piece were carried over the fuel assemclies and then rotated so that the flow could n!
longer carry it, the piece would fall on top of the fuel assembly or between fuel assemblies.
The concern for potential interference of small pieces with fuel assembly and contret rod operation is discussed in section 4A.2.3. The probability of interference of small pieces in the fuel assembly or control red operation is judged to be negligible.
4.4.2.5 Spray Nozzle Each spray nozzle consists of two 1-inch elbows fabricated of Type-304 stainles which are welded to the sparger. In order to generate a loose nozzle, a through-wall crack 46 u
- ei n .
9 EER O. 93-0479 Revision No. 0 I
Of Aff C*P2 fAs erry9 O., n G&NES5tgralzI& 0 would have to propagate 360' around the nozzfe. A loose nozzle would most likely c rest on the top surface of the ccre plate or on the top surface of the top guide. The flow velocities in these regions are insufficient to lift the nozzle (Reference 5); thus, it will rema one of the above-rnentioned locations.
I Sine the nozzle cannot be lifted by the flow and since the nozzfe cannot fit thro steam separator, it will not cause any flow blockage at the fuel assembly inlet ortfices. The i nozzle is too large to fit betwoon two fuel channels; thus, it cannot cause any control ro interferences. ,
4.8 Conclusions i
The core spray line and ccre spray sparcer at BSEP-1 are expected to remain intact:;
therefore, it is highly unlikely that pieces of the core spray line or sparger will break off. From the above evaluation it is concluded that the probability for unacceptable corrosion or other chemical reaction due to loose pieces is zero. The potential for unacceptable flow bl or other camage to the fuel assemelies is negligible. The potential for unacceptable control red intorforence is negligible. Thcrofore, it is concluded that there is no safety concern posed by any postulated loose parts.
i i
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1 47 te e
. ~. . . . . . - .
J!1 19 '93 12:49Af1 GENE ENGRG J2d55 EER No. 93-0479
, Revisita 1;0.'O
{
GENSW142-1022 Rw. t l
.I a -
SEPARATORS i A {
CORE 8 PRAY 8 SPRAGER I "
UPPER PLENUM i ANNULUS 3 q a
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7
.- e Figure 41: Loose Piece Potemial Upward Flow Path i
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EER No. 93-0479 Revision No. 0
- GENS.G;1-101028 Rw. O i Figure 4-3:
. Fust Assemblies and Control Rod Module l
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ASSEMBLIES -
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- 1. TOP FUEL GUIDE i
- 2. CHANNEL FASTENER
) 3. UPPERT1E PLATE '
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- d. EXPANSION SPRING
- 6. LOCKING TAB I 6. CHANNEL
- 7. CONTROL ROD ,
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- 8. FUEL R00
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- 11. LOWER TIE PLATE -
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- 12. PUEL SUPPORTPIECE .
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EER No. 93-0479 Revision No. O GENE 521101Glz Aw.O -
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EER No. 93-0479 Revision No. 0 GEN &551015liBlw.O Figure 4,g,* y'f90st Piece That Can Fit Through the Turnin9 ano(EndView) 2.a a 0.7a h.
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4-12 se a
EER No. 93-0479 4
Revisicn No. 0 G&N552F141022 Rw.0 5.0 IMPACT ON ECCS ANALYSIS 5.1 Limiting Break Size and Single Fallure Analysis For BSEP-1, there are no single failures for any break location (other line break) that can result in less than one core spray system injecting wa plenum above the reacter core. For a core spray line break, there are always a low pressure ECCS pumps injecting water into the RPV, thereby ensuring that not a limiting event.
For medium and large break sizes at any location (which depressur relatively quickly), the most limiting failures are those tnat result in the least numb pumps remaining operable (i.e., injecting water into the RPV).
The only two single failure candidates that are potentially limiting for med breaks sizes are:
- 1. Diesel Generator Failure 1 core spray (LPCS) + 1 Low Pressure Coolant
- injection (LPCI) + High Pressure Coolant injection (HPCI) + the ADS cperable.
2.
LPCI Injection Valve Failure - 2 core spray (LPCS) + HPCI + the ADS operable.
Since the HPCI is steam turbine powered, it is not a significant contribut medium to large breaks which depressurize rapidly. Also, since the function of the Au Depressurization System (ADS) is to depressurize the reactor as a backup to th contributes little toward mitigating medium and large break LOCAs. Therefore, failure candidates 1 and 2 each result in a dependence on only two ECCS pumps.
Accoroing to the reload analysis, failure candidate 2 (LPCI injection valve fa limiting by a large margin because of the conservative modeling of Counter Current Limiting (CCFL) at the fuel assembly upper tie plates. The calculation limits the cool delivery or downflow from the core spray systems to the fuel bundles and furthe core reflooding cy neglecting the water held back in the upper plenum.
5-1 n 'a ce
EER No. 93-04*79
. Revision No. 0 GENFE21147-10!22 Rev. O Both single failure candidates (1 and 2) were re-examined for large brea wnether there would be a change in the limiting case assuming an additional 100 reduction (an initial 100 GPM leakage allowance is conservatively assu analyses) in the core spray system with the cracks. The limiting single failure location were found not to change. This is due to the conservative treatment o neglects the core spray water held back in the upper plenum, which is approxima the total core spray flow (Reference 6).
5.2 Impact of Core Spray Lins /Sparger Leak on ECCS Analysis LOCA analyses will not be affected by a change in spray distribution due to a (large or small) in the core spray sparger. The reason is that the cociant injected upper plenum will either disperse uniformly into a pool of water above the core or will through the core to the lower plenum producing rapid reflooding (Reference 5).
Therefore, LOCA evaluation need only be performed for large limiting break sizes outside t the current limiting single failure.
From Section 3, the crack growth is expected to arrest prior to reaching 180 d 1e maximum potential leakage through a 180 degree crack in the core spray line be less than 9 GPM. This is insignificant when compared to the rated flow assume reload licensing analyses of 4,625 GPM per core spray system. The core spray sy includes a design allowance of approximately 100 GPM to allow for leakage through th hete and the thermal sleeve located between the T-box and vessel nozzle. Ther a LOCA, the combined leakage through the through-wall crack and the vent hole the thermal sleeve (31 GPM) will be well within the margin (100 GPM) inherently assume the core spray system. Thus, there should be no impact on either core spray or ECCS performance. Considering the rated flow of a core spray system is actually 4,725 GP 100 GPM leakage allowance is conservatively assumed in the licensing analyses), the e are negligible.
It should also be noted that during postulated LOCA the core spray pump would be operating close to their run-out flow capability (::9,500 GPM). The combined effec of a high flow and the significantly lower developed pump head (or pressure in the line) would further support that the leakage is negilgible.
A bounding ECCS evaluation was performed for Brunswick Unit 2 (Reference 6) wh proved that the leakage expected from the core spray line crack will have negligible imp 52 2a em -
EER No. 93-04'79
.- Revision No. 0 GEN &521-101Gl2 Re:0 the current LOCA response. The analyses can also be applied to BSEP-1. This entailed reanalyzing the limiting Design Basis Accident (DBA) LOCA even additional 100 GPM reduction in the core spray flow rate. This represent allowable value. The results of this evaluation demonstrated that the effec LOCA response is negligible.
5.3 Conclusions Based on the review cf References 5 and 6 analyses results as summarize concluded that the cracks in the 8-foop core spray sparger and piping outside the shro not impact the present MAPLHGR for BSEP-1.
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EER No. 93-0479
.- Revision No. 0 GENES 21142-1W2 Rw. O
6.0 REFERENCES
1.
USNRC IE Bulletin No. 80-13, " Cracking in Core Spray Sparger," May 12,1980 2.
GE Document No. 22A6498, Revision 0, " Core Spray Safe Ends, Design Brunswick 1."
3.
GE Drawing No. 794E972. Revision 0, " Reactor Assembly, Modification, Br
.4 NUREG-0313, Revision 2, " Technical Report for Material Selection sn Guidelines for BWR Coolant Pressure Boundary Piping," U.S. Nuclear Commission, January 1988.
5.
NEDO-22229, " Core Spray Sparger Crack Analysis at Brunswick Steam Electr Unit 1," GE Nuclear Energy September,1982.
6.
Cornwell, KF. and Stevens, G.L., and Tran, P.T., EAS-14-0388, " Core Sp I Crack Analysis for Brunswick Steam Electric Plant - Unit 2," GE Nuclear Energy, March 1988, !
i
- 7. Kiss E., Heald, D.A. and Hale, D.A., GEAP-10135, " Law Cycle Fatigue of Pr Piping," January 1970.
8.
Ranganath, S. and Mehta, H.S., " Engineering Methods for the Assessment of D Fracture Margin in Nuclear Power Plant Piping," Elastic-Plastic Fracture: Second Symposium, Volume 11 - Fracture Resistance Curves and Engineering App ASTM STP 803, C.F. Shih and J.P. Gudas, Eds., American Society for Testin Materials,1983, pp.11309 11330.
9.
DeSalvo, G.J., Ph.D. and Gorman, R.W., "ANSYS Engineering Analysis System Use Manual. Revision 4.4," Swanson Analysis Systems, Inc., Houston, PA, May 1989.
10.
Paris, P.C. and Sih, G.C., " Stress Analysis of Cracks," Fracture Toughness te its Applications, ASTM STP 381, American Society for Testing and Materials,196 pp. 30 - 83.
6-1 es e
EER No. 93-0479 Revision No. 0 GENES 5141LE2 Rev.0 11.
Rocke, D.P. and Cartwright. D.J., " Compendium of Stress intensity Fact Majesty's Stationary Office, The Hillingdon Press,1976.
12.
Hale, D.A., Yuen, J.L., and Gerber, T.L. " Fatigue Crack Growth in Piping a Steels in Simulated BWR Water Environments," GEAP-24098, January 1978.
6-2 cv'd
- u_ 22 '93 37:IEFM GDE OGG J2455
.- i En ib (
GENF57314NW2 Rev.O APPENDIX A:
STRUCTURAL ANALYSIS OF THE BSEP-1 PLANT COR SPRAY PIPE :
i A-1: Stress Results The stress results given in Table 3-1 of Section 3.2.3.1 of this report are develop ,
this section of the Appendix. The stresses were determined by applying dead weight, s and flow impingement loads to the finite element medel developed for the core spray Figure 3-2). The calculation of these loads is given here. Also included are the calculation of the stresses due to pressure and flow teacs as well as the total combined primary st given in Table 3-1.
Weicht of Lines:
An equivalent density was input to the ANSYS finite element model to include both the
_ weights of the pipe and captured water. This equivalent density is calculated below:
Metal density = 0.286 lb/in*
Water density = 62.4 lb/ft' = 0.0361 lb/in*
Pipe size = 5 inch scheoule 40S stainless steel OD = 5.563", t = 0.258", ID = 5.047" i
I Metal area = (x/4)(5.5632 - 5.0478) = 4.3 in*
Water area = (n/4) (5.0472) = 20.0 in' Metal weight = (0.286 lblin*) (4.3 in') = 1.230 lb/in j
Water weight = (0.03S1 lb/in*) (20.0 in2) = 0.722 lb/in Adjusted density = (total weight)/(metal area)
= (1.230 + 0.722) / 4.3
= 0.454 lblin' = 0.0012 slugs /in' A-1
JUL 20 '93 27:37PM GENE ENGRG J2455 EER Ho. 93-0479
.- Rovision No. 0 GEN &5516152 Re:0 Imoincement Leads (90' Deflection of Flowk F = PA = pV8 dug D = 5.563"/12 = 0.464 ft Assume downcomer flow. V = 5 ft/sec (conservative):
For water, p = 62.4 lb/ft*
F/L = pV'D/g = (62.4)(52)(0.464) / 32.2 = 22.5 lb/ft = 1.87 lblin The nodes of the finite element model are spaced (on the average) 5' apart. Th following load will be applied to all nodes comprising the horizontal arms of the c (nodes 10 - 40):
Node spacing = RO n (106.0")(5') (rJ180') = 9.25" Load per node = (1.87 lb/in)(9.25") = 17.3 lb
)
Seismic Leads: _
i From the BSEP-1 Final Safety Analysis Report (FSAR), the horizontal acceleration i
the Design Basis Earthquake (DBE) is 0.16 g and the vertical acceleration is negligibl order to provide conservative and bounding results. a typical seismic horizontal coefficient!
1.2 g was included in this evaluation.
The following accelerations were therefore applied to the finite element model:
Total vertical acceleration = Weight + Seismic
= 1.0 g + 0.16 g
= 1.16 g = 447.8 in/sec8 Total horizontal acceleration = 1.20 g = 463.2 in/sec2 The horizontal acceleration was applied in both the X and Y directions of the mod such that the resultant was 463.2 in/sec'. Thus, the horizontal acceleration applied to b directions of the model was:
A-2
' JUL EO '93 27:37Pt1 GEtE ENGRG JE455 EER No $3-C479
. '* Revisleet No. 0 GENE 55101Gl2 Rev.0 463.2 / d = 327.5 in/ sec' Pressure / Flow Loads:
Rated Flow = 4,625 GPM Maximum Flow = 6,000 GPM (Reference 5)
Q = (6,000 GPM) (1 min /60 see) (1 ft*/7.48 gal) = 13.37 ft*/sec F = p(Q/2)(V) = p(Q/2)(Q/A) = (62.4) (13.378) / [2(32.2)(n/4)(5.047/12)*] = .1,247 lb AP = 70 psi @ 6,000 GPM (Reference 2)
Stresses Due to Leads: l 4
Pressure:
op= (70) (x/4) (5.0478) / [(n/4) (5.563* - 5.0478)] ;
= 326 psi
~ _
Flow Load: .,
op = F/A = 1,247/[(n/4) (5.5638 - 5.0478)]
= 290 psi l
i 1
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~JUL 20 '93 07:37FM GENE ENGRG J2455 EER No. 93-0479 )
. Revision I!o. D GENES 2M&15t?,Rn O I
-i Imoincement. Weicht and Seismie:
Stresses due to the above leading were determined using the finite element model of :
the internal core spray piping. From the ANSYS results, the maximum of the stresses at
{
nodes 23-27 were used since they are in the area of the cracks. The maximum stresses are given below.
c ,
I C D!R = Axial Stress = 54.3 psi t eBEND = Bending Stress = 2229 psi i cTOR = Torsional Stress = 144.7 psl cTAu = Shear Stress = 186.0 psi Cembining all of the crimary stresses, the following values are obtained:
Primary Membrane = Pm =cp+e p +c arg
= 290 + 326 + 54.3
= 670 psi Primary Bending = P,=yemo"-e73,2
=J22292 +144.72 = 2,233 psi !
I The shear stress eTAu, is small and its effect is negligible so it is not included.
1 i
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JUL 22 '93 27:22PM GENE ENGRG J2455 EER No. 93r.0479
. Revision No. 0 G&N&5211615l2liw.0 A 2: Fatigue Crack Growth The results of the fatigue crack growth analysis due to thermal gradients across the core spray piping presented in Section 3.2.3.2 are developed in this section of the Appendix. '
The first event considered is a HPCI injection in which ccid water (100*F) from the f;;h;' >
spargers impinges on the het core spray line (550*F). Conservatively assuming the -
temperature at the bottom of the core spray piping remains at 550*F, a thermal bending stress is applied across the pipe cross section. This condition is approximated by the following sketch:
I i
Tout = 100'F Vout = 5 ft/sec !
v v hh
, Tin = 550*F To = 550*F i
i The second event considered is the actuation of the core spray system. In this event, cold water (50*F) is injected through the hot cere spray line (550'F) which induces a uniform thermal membrane stress througnout the pipe cross section. This condition is approximated by the following sketch:
Tout = 550*F Vout = 5 ft/sec hvhvhvv
, Tin = 50*F 3
/~%
l To = 550*F i
A-5
- JUL 20 '93 07:33Pf1 GENE ENGRG J2455 EER No. 93>0479
. Revision No. 0 GENFS51&talth>v.0 Heat Trensfer Coefficients:
The heat transfer coefficients for each event were computed using classical heat transfer methods. For the HPCI injectlen event, the outer heat transfer coefficient is calculated assuming a cylinder in turbulent cross flow. The heat transfer coefficient for a cross flow fluid temperature of 100*F is:
hog = 992 Btu /hr ft" 'F The inner surface heat transfer coefficient assuming fully developed laminar. flow
(@550*F) due to leakage through the vent hole is calculated to be:
h in = 2.83 Blu/hr ft' 'F For the core spray injection event, the outer heat transfer coefficient is again calculated assuming a cylinder in turbulent cross flow. .The heat transfer coeffielent for a cross. flow fluid temperature of 550*F is:
hog = 1497 Btulhr ft* 'F The inner surface heat transfer coefficient is calculated assuming turbulent flow through a cylinder (@ 50'F):
h in = 4251 Stu/hr ft* 'F Temperature Gradients Across Waff of Pice: - ~
Using the heat transfer coefficients identified above, the temperature change across the pipe was calculated assuming one-dimensional, steady state conduction. For the HPCI injection event, the inner and outer temperatures of the core spray piping at the top of the pipe was calculated to be:
Ti = 100*F T = 100*F A-6 m
JUL 20 '93 07:SSPN GETE DGRG J2455 EER No. 93-0479 j
. Revision No. O GENES 21161lE2 Rev.0 l
Assuming the temperature of the bottom of the pipe remains at 550*F:
1 AT = 550' - 100* = 450'F For the core spray injection event, the inner and outer temperatures of the wall were I calculated to be:
Ti = 50*F T. = 550'F Thermal Stresses:
The thermal stresses for both events are as follows:
The gross bending membrane in the cracked section, stress due to the HPCI Injection is calculated to be:
o = 42.7 ksi The through thickness bending stress due to the core spray injection is calculated to be:
a = 85.4 ksi A-7
JUL 20 '93 07:39PM GEtE ENGRG J2455 EER 340. 93-0479 Ravicion No. O G&N&523 IGRE2 Rev.0 Stress Intensity Factors-Stress intensity factors were calculated based on the thermal stresses calculated for each event. For the core spray injection, the expression used for K, is (Reference 10):
K' = O(1+ v)
(3 + v) where a = bending stress (ksi) = 85.4 ksi" a = crack length (in) = 2.6" (1/2 = 5.2 / 2 = 2.6")
v = Poisson's ratio = .287 K, =
'
- I+'O = 95s6 ksi4 (3 + 0.287)
For the HPCI event, the expressionused for Ki is (Reference 11):
K, = eM(G, - G,) -
where i a = Bending stress (ksi) = 42.7 kal ;
a = Crack length (in) = 2.35" Gm = Membrane stress contribution = 1.62 G3= Bending stress contribution = .14 K, = 42.7dn2.6(162-(-0.14)) = 214.8 ksid 7
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JuL 20 '93 07:29PM GENE EfGRG J2455
- EER No. 93-0479 Revision No. 0 GE-N&S21-14210RE Rev. 0
,QI.g,gg Growth Rete:
Using the values of K, calculated above, the fatigue crack growth rate was determined using experimentally determined curves for 304 stainless steel in a simulated BWR environment (Reference 12). Conservatively assuming Kmin = 0, AK is equal to K i m x. From Figure 4-1 of Reference 12, the crack growth rates for the events considered are:
HPCIInjection. Aa 0.0065 in/ cycle An Core Spray injeetion: 0'
- = 0.16 in/ cycle on Assuming one event eacn for the next 12,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of het operation, the total fatigue crack growth is 0.167 in at each crack tip. The increase in crack length is two times Aa/in to account for growth at both ends of the crack. Thus, the crack growth due to fatigue is 0.33 in.
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- i FORM 1 k EER No. 93-0479
.I g' T ENGINEERING EVALUATION Rev. No. 0 REPORT Page No. 1 of 19 z ff O g3 1 Referene. ACR, LER, WR/JO, etc. PT90.1 For Refuel #8 File No. 1005 g 2 Brief description of item / activity Evaluate Unit 1 Oe 1 5 Core serav Invessel Pioino rollowina rvvI Ex==inations [/] Class A (Q-List)
[ ] Class B-3 (FP-Q)
$ I,g3 Disposition [ ] Other Cr Ej hag [ ] a. Use/ acceptable as is
- Qcalified Technical
[ } b. Permanent repair / rework Q sR* [/] c. Temporary change Reviewer if Quality Class A and box 4b LA. 34 =
[ ] Temporary repair, Erpiration Data checked
[ } Temporary modification 2 . g 8$p [/) CA/STEI ([ ] Preliminary) Empiration Date End of RF #9
[ ] d. Information Transmittal I $ t, T 1 e. Other 3 Final Resolut' ion ,. . .
a.
- . ' [ ] Complies with system DBDs, FSAR, design, code, and quality requirements.
- b.
(See definitions for Design Change and Configuration control).
[/) Acceptable deviation frcus' system DBDe, FSAR, design, code, or quality
[ requirements. Safety review (AI-109) required.
. l~5 Follow-up Requirements
~~
[ ] a. Survei.llance activities, responsible group (s)
/ [/) b. Action items, responsible ~ group (s) Tech Suvoort J [ ] c. None y, YES NO -
[ ] [/] Changes to system DBD, FSAR, design, drawing, code, or quality
,...,. requirements are requLred. due; to this EER. (Provida details on
-.~
Attachment 3 within 10 wokking' days from EER approval.) ~
6J Review / Approval W @ NOTE: If Blocks 3d and 4a are checked,.only the Responsible Engineer and_
g r Engineering Supervisor signatures are required. However, other reviewers
) S Z may be necessary based on the disposition.
3 Responsible Enghneer C Data
) W d Print Q Sijnature Grourf . / .
[/)Yes [ )No Technical Review
- Adf" Da 7[ l */3 Engineering Supervisor bo/8M "
Date 9 Print Signature
[ ]Yes [/)No EQ Review Date
[ )Yes [/]No ANII Review Date
[ )Yes [/]No PNSC Review .n Date Approved Nd Print bM/ Date t D Signature INDEFENDENT REO SAFETY REVIEWS (Reference 6.2.6)
NOT REO REVIEW COMPLraru DATE
[ } [/) CNSR (Prior to Approval) REPt
[ } [/) ':NSR (Review after Approval) -
Other 7 91stribution:
BNP Records Management (EER File) Supervisor - ISI NED BESS Section Manager. Manager - Operations Staff Manager - Maintenance Responsible Engineer Nuclear Englneering Department Raleigh Specialist - Regulatory Compliance Q-List /EDES Coordinator - PEG NED Design Control EDC - Technical Support On Site NAD Manager - Training Department NED EQ Group - Raleigh BSEP/Vol. EE/EEP-12 23 Equivalent to Rev. 33
s ENGINEERING EVALUATION EER No. 93-0479
- e c o. O LIST OF EFFECTIVE PAGES g sfg[
t List of Effective Pages PAGE INITIAL REV REV REV REV REV NO. ISSUE NO. NO. NO. NO. NO.
1 0 2 0 3 0 4 0 i 5 0 '
6 0 7 0 '
8 0 '
9 0 '
10 0 11 0 12 0 13 0
- 14 0 '
15 0 16 0 i 17 0 i
18 0 19 0 i
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ZNGIIEERING EVALUATION EER No. 93-0479 .!
TABLE OF CONTENTS Revision No. O l Page No. 3 1 Y
t b
TABLE OF CONTENTS i i
Sections >
Page ;
Traveler (Form 1) . . . . . . . . ... . . ..... ... .. .. .. ....... 1 !
r List of Effective Pages . . . . ... .. .. . ... .... .. . ...... 2 i i
Table of Contents . . . . . . . . . .... ... ......... ................ 3 !
Section 1 - History ....... .. .. . ................ . .. ..... 4 !
Section 2 - Refuel No. 8 IVVI Results .. .
.............. ....... ..5 .
i Section 3 - Evaluation of Indications . .. . ... . ... ... .6 :
?
Section 4 - Disposition of Unit 1 CS Spargers/ Piping .............. .........6 l References ...... . . .. .. . .. ...... .......... -. ... . 7. !
EER Action item Notifications . . . . . . . ..............................8 i Safety Review ....... . ..... .. ............ .......... 9 '
EQ Impact EvaluationForm .... ..... ....... ......... .. ....... 18 Attachments List . . . . .............. .. ...... ...............19 f
e I
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?
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4 FORM 3 ENGINEERING EVALUATION EER No. 93-0479 Revision No. O Page No. 4 This EER documents the In-Vessel Visual Inspections (IVVI) and subsequent evaluations performed on the BSEP Unit 1 Invessel Core Spray piping and spargers during Refuel Outage No. 8; summarizes the results; and provides justification to use the spargers for
' another operating cycle in the as-found condition. This EER is identified as Quality Classification A on Form 1. The internal core spray piping and spargers are non-ASME ,
Code components. i.e., they are not reactor coolant pressure boundary components, however they are classified as safety related since the core spray system is part of the Emergency Core Cooling System. The function of internal core spray piping and spargers is to provide a contained flow path to direct the water to the core region in the event of a LOCA.
1 IIISTORY OF CORE SPRAY PIPING & SPARGER NON-DESTRUCTIVE ,
EXAMINATIONS '
1.1 Introduction 1.1.1 In accordance with IE Bulletin 80-13 (Ref 1) the reactor pressure vessel internal piping and spargers associated with the core spray (CS) system are visually examined with a remote operated underwater camera during each refueling outage as part of !
Periodic Test PT-90.1 (Ref. 2). The inspection is recorded on video for a documentation record.
1.1.2 Cracking in the in-vessel CS spargers and piping is an industry concern. The first i
~ instance of cracking in CS spargers occurred in 1978 at Oyster Creek which eventually resulted in the issuance of IE-Bulletin 80-13 in 1980. The first cracking ;
appeared in piping adjacent to the tee box in 1985 at Peach Bottom. One of the units at Browns Ferry and the Monticello plant have since found cracks in the piping-adjacent to the tee box. Monticello is currently operating with the existing crack in ,
the as-found condition. (Repairs are planned in the next refueling outage.)
l.1.3 The BSEP Unit 1 CS piping has never had any reported indica' ions in previous exauinations of the RPV internal CS piping and spargers.
1.1.4 BSEP Unit 2 is currently operating with two cracks in the RPV internal CS piping &
spargers. One crack is in the 90* unuth (north loop) piping to tee box circumferential weld and the other mdication is in an upper sparger tee-to-arm ;
circumferential weld. The upper crack was ultrasonically examined to verify that it was through wall. These flawed pipe /spargers have been repaired by the use of ;
brackets / clamps which provide full structural reinforcement to the piping equivalent to a welded joint. The Unit 2 piping has been analyzed (Refs. 3 & 5) for both structural adequacy and the effect of potential leakage through the cracks on the ability of the CS system to deliver cooling water to the core. The conclusion was that the existing cracks with the addition of the clamp / brackets are acceptable for continued operation. ;
The amount ofleakage through the maximum predicted crack size was within the j
design margin of the CS system. In fact, the CS piping outside the shroud has been i i
BSEP/Vol. XX/ENP-12 25 Equivalent to Rev. 31
~f FORM 3 ENGINEERING EVALUATION .EER No. 93-0479 Revision No. o !
Page No. 5 i
J analyzed for postulated cracks in all four tee box welds and the predicted leakage was still within the design margin of the CS system. {
1.1.5 Unit 2' operated for two refueling cycles with the crack on the nonh loop CS piping !
and one cycle with the lower indication as found before repairs were implemented. t The upper crack was approximately 4.9" long at the stan of the second cycle of .
operation before repairs were implemented. This was evaluated by General Electric Co. in Ref. 3. -l 2 REFUEL NO. 8 EXAMINATION LESULTS ,
2.1 Inspection Results i
2.1.1 Two linear indications were found in the Unit 1 in-vessel core spray piping (B-loop),-
- by visual exammations using a remote operated underwater camera as depicted in i Figure 1. One indication is in the heat affected zone of a circumferential weld which is located in the in-vessel piping between the B-loop inlet nozzle and the sparger.
This weld is located approximately 18" downstream of the B-loop tee box. This linear indication is approximately 4" long and is in the heat affected zone of the ;
circumferential weld. , "
2.1.2 The other indication was' found on a tee-to-sparger arm circumferential weld on one !
_ of the lower B-Loop spargers. This indication is approxima:ely 3" long. The tee and sparger are located inside the shroud at a lower elevation than the inlet piping where .;
the other indication is located.
' Inlet '
~ Indication is '!
,, g- I cated here in
,_ upper pipmg l
- x I
13 I
l (k 4 ri '
( l I N',i [/ ' l I _I .
i 1
Indication location in sparger Figure 1 - Internal Core Spray Piping
.BSEP/Vol. XX/ENP-12 25 Equivalent to Rev. 31
l FORM 3 ENGINEERING EVALUATION EER No. 93-0479 [
Revision No. O l Page No. 6 3 EVALUATION OF INDICATIONS 3.1 The indications were evaluated by General Electric Company in Ref. 4 for CP&L for (1) the effect on the stmetural integrity of the in-vessel core spray piping; (2) the effect of leakage through the assumed through wall indications and the impact to the ECCS analysis and (3) the effects of any postulated loose parts on safety related ,
equipment in the reactor pressure vessel or the effect on invessel components.
3.2 For conservatism the indications were assumed to be through wall. (The upper A .
loop Unit 2 indication was documented by ultrasonic exammation to be through wall). !
The indications are likely the result of IGSCC. Irradiation Assisted Stress Corrosion
- Cracking (IASCC) is not expected to be a contributor to crack growth in the core -
spray spargers. Several engineering estimates have been mad':. for the integrated ,
fluence for the design power operating life (40 year life, 32 years of which are at full power) in an area closer to the reactor core than the core spray spargers. All of these ,
estimates are based upon conservative inputs, and all fall well below the threshold '
value for high stress conditions cited in EPRI research.
3.3 The conclusion of the stmetural analysis was that neither indication would grow enough in the next operating cycle to affect the stmetural integrity of the invessel piping or sparger. All design margins for structural integrity of the in-vessel core spray piping and spargers would still be met at the end of the next eighteen month operating cycle.
3.4 Calculations were performed by GE to estimate the amount ofleakage through the indications (assumed as through wall cracks) and the effect on the ability of the core spray system to deliver the design quantity of water to the core region in the event of a core spray injection. The conclusion is that even using a very conservative leakage rate through the indications, there is sufficient margin in the existing core spray system beyond the design minimum such that the amount lost through the indications would not prevent the core spray system from performing as designed. (The lower indication on the sparger is actually located inside the shroud therefore any leakage through this crack would be delivered directly to the core region unlike the upper indication which is outside the shroud).
3.5 The effect of fragments of the in-vessel core spray piping and spargers breaking loose was considered and there was no postulated adverse effect on any safety related equipment. The subsequent effect of any loose fragments on reactor vessel control rod drive components, fuel assemblies, or any reactor vessel internal components was considered insignificant. i 4 DISPOSITION OF THE PIPING /SPARGERS AS-FOUND IN REFUEL OUTAGE NO.8 4.1 The Unit 1 internal core spray piping is acceptable in the as-found condition for the next operating cycle of Unit 1. There is no postulated scenario involving the internal core BSEP/Vol. XX/ENP-12 25 Equivalent to Rev. 31
FORM 3 l ENGINEERING EVALUATION EER No. 93-0479 1 Revision No. O ,
Page No. 7 t spray piping that will affect the safe operation of the plant and all design margins for the core spray system will be maintained during the operating cycle. The predicted crack length at the end of an eighteen month cycle will not reduce the structural and hydraulic design margins for the piping and spargers below allowables.
The condition of the internal core spray piping does not impose any restrictions to plant ;
operation for the next operating cycle. -
l 4.2 The core spray piping is routinely examined every refueling outage as part of PT-90.1, therefore the piping /spargers will be re-evaluated and/or repaired in Refuel Outage. No. 9 l based upon the results of the next examination.
l 1
'1 REFERENCES i l
- 1. USNRC IE-Bulletin 80-13. " Cracking in Core Spray Spargers", May 12, 1980.
- 2. OPT-90.1 for Unit 1, Refuel Outage No. 8 (Outage B109), " Core Spray /Feedwater Visual Examination".
i
- 3. General Electric Company Report No. EAS-03-0190 (Supplement 1 of EAS-14-0388), Core '
Spray Line Crack Growth Analysis Update for Brunswick Steam Electric Plant Unit 2 January 1990.
- 4. General Electric Company Report No. GE-NE-523-97-0793, " Core Spray Crack Analysis for ,
Brunswick Steam Electric Plant, Unit 1. July,1993 l 5 General Electric Company Report, " Core Spray Sparger Crack Analysis at BSEP - Unit 2, NEDO 22171, July 1982.
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ENGINEERING EVALUATION EER No. 93-0479 Revision No. O Page No. 8
?
FORM 4 EER ACTION ITEM NOTIFICATION FORM TO: [ ] Manager - Operations Staff
() Manager - Maintenance I) Technical Support Manager -
DG Manacer - Tech Succort '
P FROM: Manager - A/6D SL'BJECT : EER Action Item No. 1 Corporate Priority 6A Is this EER a temporary change? [/] Yes [] No Expiration date End of Unit 1 Refuel No. 9
[ ] Temporary repair [] Temporary condition [/] OA/STSI Is this EER action item required for resolution of the temporary change?
[/) Yes [ ] No The following Action Item is assigned to you by the above Engineering Evaluation for completion no later than 9-/S~-93 -
Initiate a Proiect Identification, Form (PIF) to reevaluate and/or recair the Unit 1 invessel core scrav ninina~ and searners by the end of the next refuelinc outage (Refuel Outane No 9) .
This notification was reviewed with En, docG Mm>/D /AA/ /DI of the responsible organization, on "7/t //92
. Please sign below i and return this notification upon the satisfactory completion of the j specified action item.
W/ j .,),h Qf ~
j ?-224)
Responsible Enginee'r Ddte / Res [ sible Mah:ter Date To: Engineering Data Coordinator The above action item requirement has been completed satisfactorily. The reference document (WR/JO number, procedure, or DSR reference) implementing this item is:
/
Responsible Manager Date Distribution: BNP Records Management (by EDC) Responsible Engineer NED On-Site Design Control j
BSEP/Vol. XX/ENP-12 26 Equivalent to Rev. 32
P
. i EER No. 93-0479 b ENGINEERING EVALUATION Revision No. O _r Page No. 9 l SAFETY REVIEW COVER SHEET DOCUMENT NO. EER 93-0479 REV. NO. O DESCRIPTION OF TITLE: Evaluation of Unit 1 Core Sorav In-vessel Picine & Searcers 1 Assigned Responsibilities:
Safety Analysis Preparer: J. E. Gates, Jr. j Lead 1st Safety Reviewer: J. E. Gates, Jr. ;
2nd Safety Reviewer: R. A. Steckel 2 Safety Analysis Preparer: Complete PART I, SAFETY ANALYSIS Safety Analysis Preparer 2,2 -
Date 7/I/ $ '
3 Lead 1st Safety Reviewer: omplete Part II, Item Classification.
4 Lead 1st Safety Reviewer: III may be completed. If either question 1 or 2 is "yes," then Part IV is not required.
5 Lead lac Safety Reviewer: Determine which DISCIPLINES are required for review of this item (including own) and mark the appropriate blocks below. ,
DISCIPLINES Recuired: (Print Name) Sicnature/Date (Steo 7)
[ ] Nuclear Plant Operations
[] Nuclear Engineering
[/) Mechanical //86 Mh89 I -
v 7/8/ 'h- j
[] Electrical
[] Instrumentation & Control
[] Structural - I
[/) Metallurgy 6MNEW b', NunMS A 7/2//73
[] Chemistry / Radiochemistry
[] Health Physics
[] Administrative Controla 6
A QUALIFIED SAFETY REVIEWER will be assigned for each DISCIPLINE marked in step 5 and his/her name printed in the space provided. Each person shall perform a SAFETY REVIEW and provide input into the Safety Review Package.
7 The Lead 1st Safety Reviewer will assure that a Part'III or Part IV is completed (see step 4 above) and a Part VI if required (see 9.b of Part II). Each person listed in step 5 shall sign and date next to his/her name in step S, indicating completion of a SAFETY REVIEW.
B 2nd Safety Reviewer: P orm a S .TY R EW in accordance with Section 8.0 s
2nd Safety Reviewer DISCIPLINE:
[
Date 7*21*4 5 Echanical
V 9 PNSC review required? If "yes" attach Part V and mark reason Yes Ng below
[] [X)
{] Potential UNREVIEWED SAFETY QUESTION
[] Question 9 of Part IV answered "Yes"
[] Other (specify) :
O AI-109 Rev. 002 1
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i ENGINEERING EVALUATION EER No. 93-0479 Revision No. O Page No. 10 [
t PART In SAFETY ANALYSIS (See instructions in Section 8.4.1) ,
( Attach additional sheets as necessary) i DOCUMENT NO. EER 93-0479 REV. NO. 0 !
s DESCRIPTION OF CONDITION / CHANGE: The in-vessel core spray piping and !
i spargers were visually examined per PT-90.1 during the current refueling outage No. 8.
EER 93-0479 was written to document the examination results j and subsequent analysis of the as-found condition and to evaluate the l acceptability to operate with the piping and spargers for another refueling ;
cycle.
ANALYSIS: The invessel core spray piping and spargers are not ASME Code pressure retaining components. They are classified as safety related since '
the core spray system is part of the Emergency Core Cooling System. The circumferential weld joint indications are discussed in the following paragraphs, and the conclusion reached by analyses is that the Unit _1 core spray invessel piping and spargers as examined in this refuel outage will be acceptable for another operating cycle. '
The indications were evaluated for (1) the effect on the structural integrity of the in-vessel piping (2) the effect of leakage through the indications and the ability of the core spray piping /spargers to deliver '
cooling water to the core in the event of a core spray initiation and (3) i i
the effects of any postulated loose parts on the safe operation of the Unit. j i
For conservatism the indications were assumed to be through wall cracks.
(The Unit 2 indication discussed in the EER was documented by ultrasonic {
examination to be through wall). '
i The conclusion of the structural analysis in Ref. 1 was that neither indication would grow long enough in the next operating cycle to affect the l structural integrity of piping. All design margins for structural integrity -
of the in-vessel core spray piping and spargers would still be met at the end of an eighteen month operating cycle.
Calculations documented in Ref. I were performed to estimate the amount of leakage through the indications and the effect on the ability of the core spray system to deliver the designed amount of water to the core region in the event of a core spray injection. The' conclusion was that even using a very conservative leakage rate through the indications, there was sufficient
)
u
__ ._ _ . . _ . . _ . ~ . . .
. . 1 EER No. 93-0479 ENGINEERING EVALUATION Revision No. O Page No. 11 PART I: SAFETY ANALYSIS (See instructions in Section 8.4.1) '
(Attach additional sheets as necessary) !
DOCUMENT NO EER 93-0479 REV. NO. O margin in the existing core spray system such that the amount lost through i the crack indications would not prevent the core spray system from
)
performing as originally designed. The lower indication on the sparger is ,
actually located inside the shroud, therefore any leakage through this crack would be delivered directly to the core region unlike the upper indication which is outside the shroud.
The effect of postulated loose fragments from the in-vessel core spray ;
piping and spargers was considered ( Ref. 1) and there was no' safety concern '
identified. The effect of any loose fragments on safety related reactor 1
vessel control rod drive components, fuel tsemblies, or any other reactor $
vessel internal components was considered negligible in Ref. 1.
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. i EER No. 93-0479-ENGINEERING EVALUATION Revision No. O Page No. 12 PART I: SAFETY ANALYSIS (See instructions in Section 8.4.1)
(Attach additional sheets as necessary)
DOCUMENT NO. EER 93-0479 REV. NO. O REFERENCES (1) " Core Spray Crack Analysis for BSEP Unit 1", General Electric Co'.
l Report No. GE-NE-523-97-0793, July 1993 I
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4 ENGINEERING EVALUATION EER No. 93-0479 Revision No. O Page No. 13 PART II: ITEM CLASSIFICATION DOCUMENT NO. EER 93-0479 REV. NO. 0 Yes No 1 Does this item represent:
- a. A change to the facility as described in the SAFETY
- ANALYSIS REPORT?
- b. A change to the procedures as described in the SAFETY I] [/]
ANALYSIS REPORT? [ ]
- c. A test or experiment not described in the SAFETY [/] ,
ANALYSIS REPORT?
[] [/]
2 Does this item involve a change to the individual plant '
Operating License or to its Technical Specifications? [] [/]
3 Does this item require a revision to the FSAR? [] [/]
4 Does this item involve a change to the Offsite Dose Calculation Manual? [ ] [/]
5 Does this item constitute a change to the Process control Program!
[] [/]
6 Does this item involve a major change to a Radwaste Treatment System?
[] [/]
7 Does this item involve a change to the Technical Specification i Equipment List?
[] [/] !
8 Does this item impact the NPDES Permit (all 3 sites) or '
constitute an "unreviewed environmental question" (SHNPP Environmental Plan Section 3.1) or a "significant environmental impact" (BSEP)? [] [/]
9 Does this item involve a change to a previously accepted- l
- a. Quality Assurance Program
- b. Security Plan (including Training, Qualification, [ ] [/] )
and Contingency Plans) ? I] [/]
- c. Emergency Plan? [] [/]
- d. Independent Spent Fuel Storage Installation license? [] I/]
(If yes, refer to Section B.4.2, " Question 9," for special considerations. Complete Part VI in accorde. .me with Section 8.4.6)
SEE SECTION 8.4.2 FOR INSTRUCTIONS FOR EACH "YES" ' 'SWER . !
REFERENCES. List FSAR and Technical Specification references used to answer questions 1-9 above. Identify specific reference sections used for any "Yes" answer.
UFSAR Sections 3.6. 3.7 3.9, 3.11, 5.2, 5.3, 5.3a, 6.2, 6.3, 15.0 Specifications Sections 2.1.3, 3/4.4.3, 3.4.4.3. 3/4.4.4, 3/4.4.8. 3/4.10.4 and associated bases.
O AI-109 Rev.. 002
ENGINEERING EVALUATION EER No. 93-0479 Revision No. O '
Page No. 14 PART III: UNREVIEWED SAFETY QUESTION DETERMINATION SCREEN DOCUMENT NO. EER 93-0479 REV. NO. 0 YES NO 1 Is this change fully addressed by another completed UNREVIEWED SAFETY QUESTION determination? (See Section 7.2.1, i 7.2.2.5, and 7.9.1.1) [] [/]
REFERENCE DOCUMENT: REV.
YES NO 2 For procedures, is the change a non-intent change which I only (check all that apply): (See Section 7.2.2.3) [ ] [ ]
[ ] Correct typographical errors which do not alter the meaning or intent of the procedure; or,
[ ] Add or revise steps for clarification (provided they are consistent l with the original purpose or applicability of the procedure); or, 1
[ ] Change the title of an organizational position; or, )
[ ] Change names, addresses, or telephone numbers of persons; or,
[ ] Change the designation of an item of equipment where the equipment is the same as the original equipment or is an authorized replacement; or,
[ ] Change a specified tool or instrument to an equivalent substitute; or, l
[ ] Change the format of a procedure without altering the meaning, intent, or content; or
[ ] Deletes a part or all of a procedure, the deleted portions of which are wholly covered by approved plant procedures?
If the answer to either Question 1 or Question 2 in PART III is "Yes," then PART IV need not be completed, i
0 AI-109 Rev. 002
ENGINEERING EVALUATION EER No. 93-0479 Revision No. O Page No. 15 -
PART IV: UNREVIEWED SAFETY QUESTION DETERMINATION DOCUMENT NO. EER 93-04'79 REV. NO. O (See instructions in Section 8.4.1)
(Attach additional sheets as necessary)
Using the SAFETY ANALYSIS developed for the change, test or experiment, as well as other required references (LICENSING BASIS DOCUMENTATION, Design Drawings, Design Basis Documents, codes, etc.), the preparer of the SAFETY '
EVALUATION must directly answer each of the following seven questions and ,
make a determination of whether an UNREVIEWED SAFETY QUESTION exists.
J A WRITTEN BASIS IS REQUIRED FOR EACH ANSWER Yes No l 1 May the proposed activity increase the [ ] [/3 j probability of occurrence of an accident evaluated previously in the SAFETY ANALYSIS REPORT? !
I i
Usino the existino core sprav in-vessel ciping and scarcers in their present $
l condition does not increase the probability of occurrence of any previous 1v evaluated accident. For the next operating cycle the ability of the core i l
sprav pipino to function as originally desianed is unaffected bv the indications and the structural intecrity of the in-vessel core sorav eininc and searcers is not ieonardized, therefore the probability of a previously l evaluated accident is unchanced.
2 May the proposed activity increase the consequences of an
[] [/]
accident evaluated previously in the SAFETY ANALYSIS REPORT?
As explained in the answer for Ouestion No. 1. the existina in-vessel CS cining will function as oricinally desianed for the next operatino cycle and I there is no costulated impact on any safety related reactor vessel I components for the next coeratina evele, therefore usina the core scrav nicina and searcers in their cresent condition does not increase the consecuences of any accidents oreviously evaluated in the UFSAR. The ponsecuences of oreviously evaluated accidents are unchanced.
1 3 May the proposed activity increase the probability of [ ] [/] l occurrence of a malfunction of equipment important to safety !
evaluated previously in the SAFETY ANALYSIS REPORT? l i
Usina the core scrav einina and scarcers in their cresent condition does not increase the orobability of malfunction of safety related eauipment evaluated oreviously. The postulated ef fects of loose carts was considered and the consecuences on safety related eauipment was neolicible. The ability l
of the core scrav system to perform within its desian maroin is unaf fected by the indications.
4 May the proposed activity increase the consequence [ } [/l of a malfunction of equipment important to safety evaluated previously in the SAFETY ANALYSIS REPORT?
The consecuences of a malfunction of safety related eauipment is not increased since there is no imoact to any safety related system or component in the plant as a result of usino the core sorav invessel scareers/oicino in their existino condition for the next eichteen month operatina evele.
O AI-109 Rev. 002
4 ENGINEERING EVALUATION EER No. 93-0479 Revision No. O Page No. 16 PART IV: UNREVIEWED SAFETY QUESTION DETERMINATION i
DOCUMENT NO. EER 93-0479 REV. NO. 0 (See instructions in Section 8.4.1)
(Attach additional sheets as necessary) ,
Yes N_po 5 May the proposed activity create the possibility [] [/]
of an accident of a different type than any '
evaluated previously in the SAFETY ANALYSIS REPORT?
No as oreviously discussed the Dotential effect of any loose fracments on gI,v other safety related nlant eauinment is neoliaible. Since there is no predicted adverse effect on any safety related comnonents there is no '
possibility to create a new tyce of accident. Even thouch analysis indicates that the structural intecrity of the invessel oicino will not be adversly af fected for the next operatino cycle, a full circumferential break in the .t invessel core sprav system has already been considered and there is !
instrumentation to monitor the intecrity of~ the invessel core sprav cioino between the nozzle and the searcers inside the shroud.
6 May the proposed activity create the ossibility of a [] [/]
malfunction of equipment important to safety of a different type than any evaluated previously in the SAFETY ANALYSIS REPORT? '
~
No. usino the existino core sorav system' for another oDeratina cvele does not create the oossibility of malfunction of safety related eauipment of a different impact type than oreviousiv evaluated. There is no postulated adverse t on any eauioment important to safety. Any seaments of the pipina/snarcers that are costulated to be notential loose earts are too small to have any significant ef fect on any safety related ecuipment and the existino circumferential weld indications are well within the acceptable structural limits and hydraulic desian maroins for opera 1 ion for another evele. i 7 Does the proposed activity reduce the margin of safety as [] [/]
defined in the basis of any Technical Specification?
No other system or eauipment will be affected by the existina internal core scrav niDina and all marcins of safety for the core scrav system will be maintained. In the event of an initiation of core sprav during the next operating cycle. the loss of any water throuch the cracks does not reduce the marcin of safety for the CS system. The calculated amount of water loss is bounded by the excess design maroin that exists in the core serav system.
The structural intecrity will not be reduced below the desian marcin by operation in the next eichteen month operatina cycle. The calculated crack lenoth at the end of the next cycle is still within the allowable lenoth such that the structural intecrity is not adversly affected.
8 Based on the answers to questions 1 - 7, does this item [ ] [/l result in an UNREVIEWED SAFETY QUESTION? If the answer to any of the questions 1-7 is "Yes", then the item is '
considered to constitute an UNREVIEWED SAFETY QUESTION.
O AI-109 Rev. 002
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ENGINEERING EVALUATION EER No. 93-0479 Revision No. O -!
Page No. 17 i
PART IV: UNREVIEWED SAFETY QUESTION DETERMINATION
{
DOCUMENT NO. EER 93-0479 !
REV. NO. 0 (See instructions in Section 8.4.1)
(Attach additional sheets as necessary)
Yes Npo 9 Is PNSC review required for any of the following reasons? [] [/]
If, in answering questions 1 or 3 "No", it was determined that the probability increase was small relative to the uncertainties; or, in answering question 2 or 4 "No", it was determined that the doses increased, out that the dose was still less than the NRC ACCEPTANCE LIMIT; or in answering question 7 "No", a parameter would be closer to the NRC ACCEPTANCE LIMIT, but the end result was still within the NRC ACCEPTANCE LIMIT; then PNSC review is required.
REFERENCES:
UFSAR Sections 3.0. 4.0. 5.0, 6.0, 7.0. 10.0. and 15.0 and Technical Soecifications sections 3/4.3, 3/4.4. 3/4.5 and associated desian bases.
This Unreviewed Safety Question Determination is for the following DISCIPLINE (s) : (Additional Part IV forms may be included as appropriate.)
[ ] Nuclear Plant Operations [ ] Structural
[ ] Nuclear Engineering [/] Metallurgy
[/] Mechanical [ ] Chemistry / Radiochemistry ,
[ ] Electrical [] Health Physics
[ ] Instrumentation & Control [] Administrative Controls t
O AI-109 Rev. 002 ,
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ENGINEERING EVALUATION EER No. 93-0479 '
Revision No. O Page No. 18
'i F
ENVIRONMENTAL QUALIFICATION IMPACT FORM (EER-EQIF)
Will the evaluation, on either a temporary or permanent basis:
i 1.
Justify the deletion of equipment / common components from the BSEP EQ program? .{
[ ] Yes [X] No -
2.
Justify the addition of (already existing) equipment / common components to the BSEP EQ program? j
[ ] Yes [X] No !
- 3. Authorize the repair of EQ equipment / common components with other than I cualified like-in-kind equipment / components parts? !
[ ] Yes [X] No
- 4. Affect the existing installation or interface (of EQ equipment / common ,
component applications) as may be designated in EDBS and/or in the ,
(
qualification data package (including changing the type of interface / installation)? ;
[] Yes [X] No l
- 5. Justify the (quality class) upgrade of equipment / common components or '[
component parts which could be utilized in EQ applications? !
[ ] Yes [X] No l
. 6. (Re) Define qualification parameters (e.g., normal or.LOCA/HELB environmental conditions, postaccident operating time requirements, j essential passive / active _postaccident operating requirements, !
qualified life assumptions /results, etc.) for specific EQ equipment? '
[] Yes [X] No i
- 7. Provide an EQ-related justification for continued operation (as required per PLP-02, Section 4.4.3.3 or 4.4.4)? {'
[ ] Yes [X] No l
- 8. Provide the resolution of a qualification problem (as required per f PLP-02, Section 4.4.4)?
j
[] Yes [X] No i
Notes: 1. If all no, then no further EQ consideration is required. Mark the EER Traveler accordingly as required by ENP-12 and include ,
this completed EER-EQIF within the EER package. An EQ Technical Review is not required. >
}
- 2. If any yes, an EQ impact assessment (per Section 5.3) must be '!
performed during the evaluation process. Mark the EER Traveler accordingly and include this completed EER-EQIF within the EER l package. An EQ technical review is required. '
BSEP/Vol. XX/ENP-34.1 20 Rev. 4 l P
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LIST OF ATTACHMENTS Page No. 19 !
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General Electric Co. Report No. GE-NE-523-97-0793, " Core Spray Crack Analysis for BSEP Unit 1" (50 pages). .
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