ML20209C276
| ML20209C276 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 03/20/1986 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20209C152 | List:
|
| References | |
| FOIA-87-185 GL-84-11, IEB-80-13, NUDOCS 8704280637 | |
| Download: ML20209C276 (16) | |
Text
.
UMTED STATES
/
NUCLEAR REGULATORY COMMISSION 3
wasmwoTom.o.c.aoses SAFETY EVALUATION BY THE 0'FFICE OF NUCLEAR REACTOR REGULATION SUPPORTING INSPECTION AND REPAIR OF REACTOR COOLANT SYSTEM PIPIhG, RECIRCULATION SAFE ENDS AND CORE SPRAY SPARGERS PHILADELPHIA ELECTRIC COMPANY PUBLIC SERVICE ELECTRIC AND GAS COMPANY DELMARVA POWER AND LIGHT COMPANY ATLANTIC CITY ELECTRIC COMPANY PEACH BOTT0H ATOMIC POWER STATION, UNIT 3 DOCKET NO.- 50-278
1.0 INTRODUCTION
During the Peach Bottom Unit 3 1985 refueling outage, a total of 132 a
l stainless steel welds including 7 welds overlay repaired in the previous outage were ultrasonically inspected for intergranular stress corrosion cracking (IGSCC) in accordance with Generic Letter (GL) 84-11. Of these, l
93 welds were in the recirculation piping system, 36 welds were in the l
residual heat removal system (RHR), I weld was in the core spray system l
and 2 welds in the jet pump instrumentation nozzle penetration assemblies.
The inspection sample plan was expanded from 71 welds to 132 welds after cracking was found during this inspection. The inspection results, repairs, and ths number of welds inspected in each pipe size of each system are sununarized in Table 1.
In addition, the core spray spargers and associated piping were visually examined,in accordance with I&E Bulletin 80-13.
j 1
1.1 Ultrasonic Inspection Qualified personnel from General Electric (GE) and Southwest Research
[
performed the ultrasonic testing (UT) for the licensee (Philadelphia i
ElectricCompany). The level II and III UT personnel perfonning IGSCC i
detection and sizing of crack indications were qualified at the Electric Power Research Institute (EPRI) nondestructive examination (NDE) center c
by successfully passing the respective training courses. All level I personnel were trained to the level of their involvement in the i
examinations. The licensee indicated that the two UT contractors 8704280637 870424 PDR FOIA MORIART87-185 PDR
- verified each other's finding when crack indications were reported.
The GE team generally used the " SMART UT" automatic system with 2.25 MHZ transducer in detection and sizing where configuration pemitted.
When questionable indications were encountered or signal attenuation was excessive, other transducer such as "SLIC-40", "WSY-70" or 1.0 MHZ transducers would be used.to aid in. determining the origin of the indications. The Southwest Research team' performed manually with 1.5 MHZ transducer and utilized the "SLIC-40". transducer for discrimination and sizing. The GE " SMART UT" system is a remote, automatic pipe weld scanning device interfaced with an ultrasonic imagining and data acquisition sub-system, capable of using booted or contact transducers and qualified under I&E Bulletin 83-02 for both detection and sizing of IGSCC at the EPRI NDE Center in Charlotte, North Carolina.
In addition, the system has passed the requalification test that has been required since September,1985.
In UT examination of the at'achment welds in the recirculation inlet safe ends, the GE " SMART UT" system in automatic mode was used in both detection and sizing of IGSCC. The capability of the " SMART UT" system in the detection and sizing of the cracks in the creviced areas of the safe end thermal sleeve attachment welds was demonstrated by comparing the UT results with the results determined
~
by destructive metallography on the cracked safe ends removed from the Peach Bottom Unit 2, which had the same themal sleeve design. The licensee reported that the metallographically determined crack depth was in all cases within 7.3% of the UT sized depth.
40 welds were reported to show crack indications. Of these, 10 welds were thermal sleeve attachment welds in the recirculation inlet safe ends, 18 welds were in the recirculation piping system (4-12" riser welds and 14-28" welds)and12weldswereintheRHRpipingsystem(4-20"weldsand 8-24" welds).
e j Twenty-four of the cracked welds were previously inspected in 1983 outage aftertheapplicationofinductionheatingstressimprovement(IHSI) process and reported to be not cracked at that time. The licensee indicated that the UT personnel that performed the examination in 1983 were qualified under I&E Bulletin 82-03, which required only procedure demonstrated.
In comparison with the UT personnel and equipment used in 1985 examination, they were less experienced, received very little training and did not use sophisticated transducer for detection, discrimination and sizing of IGSCC.
Therefore, some IGSCC indications were apparently misinterpreted as indications from geometrical or metallurgical reflectors. The worst cracking in those welds was reported in a recirculation outlet safe end to pipe weld
(#2-BS-02) with a maximum crack depth of 55% of wall thickness and a total length over 68% of the circumference. Because the crack locations reported at the recirculation outlet safe end to pipe welds also included unexpected cracks in the 316L safe-end, a pitg sample about one inch in diameter was removed from an outlet safe-end to verify the UT result and to determine the cause of the apparent cracking in the 316L material.
Results of this investigation indicated that the 316L was not cracked and the UT indications originated from areas where there was a change of grain size, and some local weld defect. The change of grain size was reportedly caused by the use of different rod sizes during the welding j
process.
i The welds determined to be cracked included 10 recirculation inlet safe ends which were made of 316L stainless steel, considered to be resistant to IGSCC under normal circumstances. Some of the cracks in the inlet safe-ends were located in creviced areas of the thermal sleeve attachment welds and some were in the noncreviced areas, upstream of the attachment welds. The cracking was reported to be oriented in both the circumferential and axial directions. This cracking pattern is similar to that reported in Peach Bottom Unit 2 and attributed to abusive grinding or crevice conditions.
l 1
The cracking in Peach Botton Unit 2 was metallurgically detennined to be intergranular.
In Peach Bottom Unit 3, cracking in creviced areas were found in 9 safe ends and cracks in non-creviced areas were found in 8 safe ends.
The cracking in the noncreviced areas of the safe ends was generally shallow
(< 20% of wall thickness) and short (< 2.2 inches). The worst cracking in the creviced areas was reported in safe end J with a maxmimum depth of 33% of wall thickness and a total length over 92% of the circumference.
1.2 Fracture Mechanics Analyses GE perfomed crack growth analysis for each of the 40 cracked welds for the licensee. The results of the analyses indicated that 22 cracked welds (10 inlet safe ends, 5 recirculation welds and 7 RHR welds) did not require repair because the final crack sizes in those welds at the end of the 18-month period were shown to meet the requirements in GL 84-11 (two thirds of the ASME Code IWB3640 allowable).
For flux welds, the calculated final crack depth also met the newly developed Code acceptance criteria.
1.2.1 Recirculation and RHR welds Thirty welds in the recirculation (18) and RHR piping systems were reported to show crack indications. All those welds were considered to be flux welds.
Based on GE's fracture mechanics analyses,12 such welds including 4-28" recircu.otion welds,1-12" riser weld, 6-24" RHR welds and 1-20" RHR weld did not require repair.
In GE's crack growth analyses, the Buchalet-Bamford polynomial fit method was used to calculate the stress intensity factors, and the crack growth rate corresponding to the upper bound weld sensitized materials was used to j
detemine the final crack sizes. The crack was conservatively assumed to
b 6 l have-an initial depth equal to the maximum reported depth and a length i
equal to the sum of the individual lengths. For welds treated with IHSI, the pipes were assumed to be free from the pipe weld residual stresses. Weld residual stresses typical of the large diameter (< 20 inches) pipes were applied to those welds not treated with IHSI.-
The applied stresses consisted of t'he-original design stress (pressure, thermal expansion, and dead weight) and weld overlay shrinkage stress.
For the crack growth analysis, these stresses were conservatively assumed to be membrance stresses. The design stresses were determined using the-appropriate piping stress reports. Weld overlay shrinkage stresses were determined using a piping system finite element model and the piping analysis code, PISYS. GE's calcu-lations have shown that the final crack sizes in those 12 welds at the end of the 18-month period were well within two thirds of the Code allowable limits as well as the newly developed Code acceptance criteria for the' flux welds.
1.2.2 Recirculation Inlet Safe Ends In GE's fracture mechanics evaluation for the cracked 316L inlet safe ends, the crack growth rate was assumed to reach a plateau value of 1.3x10-5 in/ hour at a stress intensity factor (K) of 40 linxksi and above. This limiting crack growth rate in the plateau area was derived by considering field data, 1
laboratory test data and the average life time water chemistry (0.5 us/cm) in Peach Bottom Unit 3.
The plateau behavior of crack growth rate at high K was reported to be shown in the sensitized 304 stainless steel and several other system over a broad range of K.
This plateau behavior is consistent with the. theories of rate limiting processes associated with stress corrosion cracking. GE also determined the attachment weld residual stress distribution in the safe end by an elastic-plastic finite element analysis.
The calculated through-wall residual stress distribution was similar to that i
found in a 12 inches diameter schedule 80 butt welded pipe..The maximum tensile residual stress in the axial orientation was reported to be 30 ksi at a location adjacent to the inside diameter surface of the creviced area.
I i
1
' 4 J
The primary stresses bounding all inlet safe ends were used in the calculation of the allowable flaw sizes. The allowable flaw depth (2/3 of the Code allowable limits) was calculated-to be 48% of the wall thickness for a fully circumferential flaw. GE's crack growth calculation, based on the peak crack depth of 33% of wall thickness and the plateau crack growth rate, shcwed that a minimum allowable operating. period of 13400 hours (18 months) could be justified for all 10 inlet safe ends because the final crack depth at the end of the period would still be within two thirds of the Code allowable limit. hhen a more realistic calculation was performed by considering improved water chemistry and average crack depth, the minimum allowable operating time for the worst cracked safe end (J) was calculated to be 47000 hours (35 months).
1.3 Wold Overlay Design GE performed the weld overlay designs for the licensee. Eighteen cracked welds required weld overlay repairs. The overlay weld metal was 308L stainless steel materials, resistant to IGSCC.
It was deposited using an automatic gas tungsten arc welding technique (GTAW) with water cooling inside of the pipe.
The overlay designs assumed a through wall fully circumferential flaw and did not include the first layer that passed the liquid penetrant examination and ferrite content test. The overlay was designed to provide a full structural pipe reinforcement and met the allowable limits in ASME Code Section XI IWB-3640.
IWB-3640 was-developed in accordance with the net j
section collapse theory with a safety margin of approximately 3 on applied loading. The calculated minimum overlay thickness varied from 0.21 to j
0.435 inch. The minimum weld overlay width was designed to be IRT, where R = radius and T = wall thickness. This minimum overlay width was shown I
by finite element analyses to be adequate for structural reinforcement and to avoid any end effects.
Inspection experience during this outage had shown that overlays designed with this width could be successfully inspected.
E l
?
i 7_
For one bi-metallic weld (10-1B-11) between a stainless steel elbow and a carbon steel pipe, the overlay was designed only to cover the weld and the area adjacent to the stainless steel pipe. The width of the overlay in weld 2-BS-8 was also shortened because the geometry of the valve fitting side of the weld prevented the use of a normal overly design width.
1.4 Core Spray Sparger Cracking The cracks at both sides of the piping to junction box weld of the "A" core spray header were identified during an inspection in accordance with ISE Bulletin 80-13. Air bubble tests were performed to verify that the cracks were through wall. Both cracks were located in the weld heat affected zone (HAZ) of the piping. One crack ran approximately 180 degrees in length and appeared to be through-wall for about 120 degrees. The other crack appeared to be about 120 degrees in length but the through wall air bubble leakage appeared to resemble a pin-hole.
GE perfomed a safety evaluation of the core spray line cracking for the licensee. The cracking was assumed to be IGSCC because it was located in the HAZ. The principal sources of stresses that cold cause cracking were considered to be welding residual stresses, could work from forming and fit up stresses from installation, as all other loadings during nomal reactor operation were determined to be negligible. GE contended that the cracks would not grow beyond 180 degrees because the residual stresses would relax as the cracks grew. Based on this consideration, GE's evaluation concluded that tk structural integrity of the cracked core spray piping would be maintained for all conditions of operation.
l l
8-GE performed several bounding analyses to evaluate the effect of the cracks on the ECCS performance, including the limiting LOCA event. The most limit-ing case evaluated assumed a loss of 10% of the flow, which was almost 1(0 times the estimated leakage rate determined from air bubble tests. No heat transfer credit was taken for the spray in the system with cracks.
The result of this limiting analysis indicated that the calculated peak clad temperature would be 2074 degrees F, which was well below the allowable limit of 2200 degrees F.
GE also p'erformed an evaluation of the possible consequences of a potential loose piece. GE's evaluation concluded that the potential for unacceptable flow blockage of a fuel assembly or for control rod interference was essentially zero. Therefore, there should be no safety concerns due to potential loose parts.
Although GE's evaluation concluded that no modifications or repairs were
~
required for safe operation, the licensee has installed two brackets at the location of the cracks to provide further assurance of core spray sparger operability and safe reactor operation.
Similar brackets were installed on the "B" core spray header although no cracks were identified in that piping.
1.5 Region I Inspection Reports Region I inspectors had reviewed the licensee's examination and repair pro-cedures, QA/QC records, qualification programs pertaining to the UT inspection,
~
weld overlay repairs and core spray line repairs performed during this outage.
The inspectors also observed the field inspection and repairs, including the mechanized ultrasonic examination of one thernal sleeve attachment weld and one jet pump riser weld, weld overlay repair of three welds and the repair of the core spray line. Region I inspectors have stated in their reports that the UT inspection, weld overlay repairs and core spray line repairs were performed by qualified personnel using qualified procedures, and met the required Codes and Standards, and NRC requirements.
I
a 2.0 EVALUATION 4
The staff has reviewed the licensee's submittals including the inspection results', GE's fracture mechanics evaluation of IGSCC, weld overlay designs, and the safety evlauation of cracking in recirculation inlet safe ends and core spray line, to support the continued operation of Peach Bottom Unit 3 for one fuel cycle (18 months) in its present configuration.
I 2.1 Scope of Inspection The licensee reported that a total of 132 welds were inspected during this outage.
In the recirculation piping system, except for 1-12" cross weld on C-riser, all the large pipe size ($_12 inches diameter) IGSCC susceptible welds were inspected. The C-riser cross weld could not be ultrasonically inspected because of geometry mismatch. However, this weld was treated with l
the IHSI process. Ten-12" riser welds overlay repaired during the previous outage did not require reinspection because all the cracks were axially oriented. The eight 22" sweepolet welds solution annealed after shop welding i
were considered to be resistant to IGSCC, and four of those welds were inspected. The large size pipe welds including the 5 welds overlay repaired in previous outage in the RHR system were all inspected. The licensee indicated that because of geometry, four 4" bypass line weldolets could not i
be ultrasonically inspected. These weldolets were liquid penetrant tested and no indications were found. Based on the above, we conclude that the 1
piping inspection performed during this outage meets the guidelines in GL 84-11.
2.2 Unrepaired Welds
\\
i The results of GE's fracture mechanics evaluation has determined that 22 of i
the 40 cracked welds do not rec;uire weld overly repair. Based on,our review of GE's evaluation and our independent crack growth calculations, we have j
some concerns regarding GE's evaluation, which are discussed below:
i I
i
. ~
' 2.2.1 Recirculation and RHR Welds During this outage, 30 welds in the recirculation and RHR piping systems were reported to show crack like indications. GE's crack growth calculations have determined that 12 of the 30 cracked welds did not require overlay t
repair. We noted that GE's crack growth calculations did not consider growth in crack length. As shown later, this is not conservative in the evaluation of some cracked welds. The method currently used by NRC staff to calculate the growth in crack length is based on the assumption that the growth in crack length is proportional to that of the growth in the crack depth, when the original crack aspect ratio is 20 or larger.
For example, if a crack of 0.5 inch in depth grew to a depth of 1 inch, its original crack length of 10 inches would be assumed to grow to a length of 20 inches. When the growth in crack length was considered in GE's fracture mechanics evaluation, 3 of the 12 unrepaired welds (20"-10-0-3, 28"-2-AS-08, 28"-2-BD-12) would require weld overlay repair because the final crack sizes of those three welds would not meet either the newly developed Code acceptance criteria for the flux welds or the criteria provided in GL 84-11. We performed independent crack growth calculations d
for those three welds. The weld residual stresses typical of large diameter j
pipe were considered in the calculations. The results of our calculations have shown that those three welds can be safely operated at least for a period of eight to nine months, but not for the entire next fuel cycle.
I 2.2.2 Recirculation Inlet Safe Ends i
l GE's calculations of the allowable operating time for the 10 cracked 316L-inlet safe ends were based on the assumption of a limiting crack growth rate of 1.3x10-5 in/ hour at a high stress intensity factor. -GE indicated that this plateau value was derived from the available test data for the j
non-sensitized stainless steel and normalized to a water chemistry equivalent j
tothelife-timeaverage(0.5us/cm)inPeachBottomUnit3. Based on a j
review of GE presented test data, we have determined that there are not enough test data to conclusively support the existence of a plateau crack l
a _~
T es:.,,,et m ed
}
growth behavior at high K for the non-sensitized stainless steel materials.
l Therefore, we performed an independent crack growth calculation assuming that the crack growth rate in the non-sensitized stainless steel will continue to increase at high K, and used a crack growth rate about five times slower than that for the weld sensitized stainless steel materials.
In our bounding calculation, we also used the axial weld residual stress distribution presented in GE's evaluation report. The results of our calculation have shown that 8 of the 10 cracked safe ends would have an allowable operating time less than a full cycle of 18 months. The allowable operating time for the worst cracked safe end (J) was calculated tobeabout10 months (7300 hours0.0845 days <br />2.028 hours <br />0.0121 weeks <br />0.00278 months <br />).
2.3 Licensee's Comitments Because of our concere upon the continued operation of the cracked inlet safe ends and welds 10-0-3, 2-AS-08 and 2-BD-12, the licensee has comitted to implement the following for increasing the safety margin during the next fuel cycle:
2.3.1 Mid-Cycle Inspection i
The results of our crack growth calculation have shown that 3 unrepaired butt welds and 8 of the 10 cracked inlet safe ends would only have an allowable operating tim of about 8 to 10 months. To ensure that those welds in question wauld operate with adequate safety margin during the next fuel j
cycle, the licensee agreed to perform ultrasonic inspection on those three i
unrepairedwelds(RHR/10-0-3, recirculation /2-AS-08and2-80-12)andtwo inlet safe ends F and J during an operating period between 8 to 10 months j
afterthestartup(SafeendsFandJwerethetwoworstcrackedsafe i
ends). The licensee also agreed to submit the inspection schedule details and acceptance criteria for NRC review and approval within 3 months after I
the start up.
i l
I i
- 12 2.3.2 Leak Detection The licensee agreed to tighten the allowable leakage limits and take immediate i
l corrective actions as soon as the primary coolant leakage limits were exceeded.
The augmented leakage limits reduced the maximum allowable unidentified leakage from 5 gpm to 2 pgm and the rate of increase of unidentified leakage in a 24-hour period from 2 gpm to 1 gpm. The details in the more restrictive leakage limits and the corresponding action statement are provided in the attachment.
1 i
2.3.3 Water Chemistry 1
Laboratory test data has shown that the crack growth-rate is strongly dependent on the water chemistry. To improve the safety margin in the operation of those unrepaired welds and safe ends, the licensee is comitted to implement operational practices that would allow the plant to be operated in a more stringent reactor water chemistry during the next fuel cycle. These operational practices were implemented during the operation in early 1985. The average reactor water conductivity during the early 6 months in 1985 was reported to be 0.29 us/cm.,
which is very good.
2.3.4 Crack Growth Monitoring As discussed above, the crack growth rate depends strongly on the water chemistry. However, it is not practical to monitor all the impurities in the reactor coolant that may have an effect on the crack growth.
Therefore, to ensure that there is no unexpected crack growth due to the inadvertent presence of the abnonnal water chemistry during operation, the licensee is comitted to install a GE developed Crack Arrest Verification (CAV) system on the recirculation system to monitor the crack growth in fracture mechanics specimens made of material that would bound the IGSCC behavior in the 316L and sensitized Type 304 stainless steel materials.
The CAV system is capable of providing continuous on-line monitoring of j
crack growth.
_ - n_,
O
. 2.3.5 Inlet Safe End Replacement The licensee has indicated that all the cracked recirculation inlet safe ends will be replaced with 316NG materials with a non-creviced tuning fork design to eliminate the crevice condition during the next refueling outage.
Based on our evaluation and a consideration of the licensee comitments as discussed above, we have determined that the continued operation of the 12 unrepaired butt welds and 10 flawed inlet safe ends for one fuel cycle (18 months) is acceptable provided the mid-cycle inspection results do not report excessive crack growth.
2.4 Core Spray Sparger Repair We have reviewed the licensee's analysis and the repair of the cracked core spray sparger. Although we may not completely agree with all of the conclusions of the licensee's analysis, the repair using welded brackets to reinforce the cracked sparger line is consistent with that applied at other plants (clamping devices), and approved by the staff. At Oyster Creek and Pilgrim plants, visual examinations were performed on cracked core spray spargers in successive refueling outages and no significant progression of the cracks were reported.
Therefore, based on the field experiences at other plants, the cracks in the core spray sparger are not expected to grow to any significant extent during the next fuel cycle. We conclude that the repaired core spray sparger is acceptable for continued operation of one fuel cycle o.
8 months. Continued operation of the repaired core spray sparger beyond the next fuel cycle will depend on the evaluation of the inspection results performed during the next refueling outage and the continued effectiveness of the reinforcing welded brackets.
i l
~
A*r s-
- 3.0-CONCLUSION Based on our review of the licensee's submittals and a consideration of NRC Region I staff's finding based on their observations of the inspection and repair programs, we conclude that the IGSCC inspection and repairs performed in accordance with Generic Letter 84-11 and the repair of the core spray spargers is satisfactory, and that the Peach Bottom Unit 3 plant can be safely returned to power and operated in its present configur-ation for an 18-month operating cycle, provided the fellowing items are satisfactorily completed in the time frame as stated:
(1) The more restrictive leakage limits and corrective actions as delineated in the section on Leak Detection should be properly implemented prior to start up.
(2) The mid-cycle inspection and the submittal of the acceptance criteria should be satisfactorily completed in the time frame as delineated in the section on Mid-Cycle Inspection.
Nevertheless, there remain residual concerns regarding the long term growth
~
of small IGSCC cracks that may be present but not detected during this inspection. Therefore, plans for inspection.and/or modification of the recirculation and other reactor coolant pressure boundary piping systems during the next refueling outage should be submitted for our review at least 3 months before the start of the next refueling outage.
Principal Contributor:
W. Koo Dated : March 20,1986
~~ ~
_wn
s.
TABLE 1 SUPMARY OF 1985 IGSCC INSPECTION AT PEACH BOTTOM UNIT 3 l
NUMBER OF WELDS i
PIPE SIZE SYSTEM (INCH)
INSPECTED CRACKED REPAIRE0 NOT REPAIRED 12" 29" 4
3 1
Recirculation 12" (SE) 10 10-0 10 12" (SE/N) 5 0
0 0
'~~ i~-
22" 10 0
0-
-0 22" (sweepolet) 4 0
0 ON,
i 28" 35 14.
10 ' ',
4 6""(head' spray) 2
'E ~
s 0
0 0'
s RHR 20" 9
l 4
3 1
20" (repaired) 5 i
m x
24" 20
~
8 2
6 -- A s.,
0 0
O Jet Pump
- 4 Instrumentation 4" (unrepaired) 2 d'
2
~
Penetration Nozzle welds m
~
Total Welds: C 132 40 1"8 22 y-
~
w
U:7" n.
9 c'
- V 7
i y, v
+r
?
Ols:
ATTACHMENT.
1 x
is o
j f~
PEACH BOTTOM ATOMIC POWER STATION - UNIT NO. 3 t lT~
ii
~
?
1.
Reactor coolant system leakage to the primary containment shall be limited to:
' j.
' / l, t With reactor coolant temperature above 212 degrees f, the leak a.
rate from unidentified
- sources shall not exceed 2flallons per minute.
b.-
When the reactor -is operated in the "Run" mode, the-rate of h
.c ange of unidentified
- leakage shall not exceed 1 gallon per minute per 24-hour surveillance ~ period.
I With reactor coolant temperature above 212 degrees F, the total c.
leak rate shall'not exceed 25 gpm averaged over any 24-hour surveillance period.
2.
Action Statement a.
If the reactor coolant system leak rate is greater than the limits in 1.a and.1.b above, reduce the leak rate to within the limits within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or be in at least Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Cold Shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b.
If the reactor coolant system leak rate is greater than the limit in 1.c above, be in at least Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Cold Shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The unidentified leakage-as determined by the dryvell sump collection and flow monitoring system, may be adjutted by an unidentified leakage seasurement.
l
^
+
i I
d 4
i b
i
,.._~.n
. - w <~rs ~ n w, u mm - <
- -. <