ML20054C156
| ML20054C156 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 04/15/1982 |
| From: | J. J. Barton GENERAL PUBLIC UTILITIES CORP. |
| To: | Snyder B Office of Nuclear Reactor Regulation |
| References | |
| 4400-82-1-0054, 4400-82-1-54, NUDOCS 8204200138 | |
| Download: ML20054C156 (28) | |
Text
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GPU Nuclear h1.
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P.O. Box 480 Middletown, Pennsylvan,a 17057 i
717-944-7621 Wnter's Direct Dial Number:
April 15, 1982 4400-82-L -0054 N
S TMI Program Office k
k
-9 Attn:
Dr. B. J. Snyder, Program Director 4 pry 91982A
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P U. S. Nuclear Regulatory Commission
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Washington, D.C.
20555 O
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- /
Dear Sir:
TG Three Mile Island Nuclear Station, Unit 2 (TMI-2)
Operating License No. DPR-73 Docket No. 50-320 Recovery Operations Plan Change Request No. 14 Reactor Coolant System Chemistry Specifications The attached request to change the Reactor Coolant System chemistry specifications is submitted for your review and approval. This change deletes the oxygen and hydrogen concentrations from, and establishes a chloride specification in the Recovery Operations Plan.
This change is required in order to process Reactor Coolant System water as detailed in the Reactor Coolant Processing Plan which was previously transmitted to you via GPU Nuclear letter, 4400-82-L-0043, dated March 23, 1982.
- icerely, f
I J.
L'.
Barton Ac Director, TMI-2 JJB:JJB:djb Attachment ec:
L. 11. Barret t, Deputy Program Director, TMI Program Office g01 8204200138 820415 i
DR ADOCK 05000320 h
PDR GPU Nuclear is a part of the General Public Utilities System J
=
RECOVERY OPERATIOi4S PLAN CHANGE REQUEST NO. 14 Tne Licensee requests that the attached change page 4.4-1 be substituted for the existing Recovery Operations Plan page and B 3/4 4-1 be suostituted for -
the existing bases page.
l REAS0ri FOR CHA!JGE In order to proceed with the processing of Reactor Coolant System (RCS) water, changes to the RCS chemistry specifications are required.
These changes fall into two categories: oxygen (0 ) control and chloride (C1-) control as 2
discussed below.
0 Cont rol 2
j During processing of RCS water, the flow path will route water from the RCS to a Reactor Coolant Bleed Tank (RCBT).
From there it will be pumped through the l
Suomerged Demineralizer System (SDS) to another RCBT. From the second RCBT it will be pumped back into the RCS. With the exception of the RCST's, the l
entire processing flowpath is through closed piping systems.
In order to minimize 0 introduction into the RCS water, a nitrogen blanket will be 2
maintained in the RCBT's while the fluid is staged therein. Even with these precautions, a residual partial pressure of 0 will remain which will 2
I increase the amount of dissolved 0 in the RCS water above its present value.
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t This increase in dissolved 0 concentration could be controlled by the 2
introduction of hydrazine into the RCS " makeup" flowpath. However, hyorazine is a strong reducing agent and as such it may reduce the sulfate presently in tne RCS to sulfite and eventually to polythionic acids leading to metal degradation.
Prevailing over all of the above, the requirement for oxygen control must be considered in the context that processing RCS wateI will precede pre-head lift inspection by only a short time.
This inspection will effectively open the RCS to atmospnere.
This operation will cause the dissolved 0 concentration in the RCS to increase to near saturation 2
conditions.
Therefore a stringent requirement to introduce a reducing agent for 0 control during RCS processing is considered unnecessary and 2
undesirable.
As this Recovery Operations Plan Cnange Request deletes the requirement to control 0, concentration in the RCS, the hydrogen (H ) concentration limit j
2 has also been deleted as H is a further means of 0 control.
2 2
Cl Control Tne IHC review of the THI-2 reactor coolant water chemistry dated January 19, 1981 recognized the loss of 0 control when the RCS is opened to 7
atmosphare.
It stated that IJRC would require procedures to reduce the Cl-concentration to less than or equal to 0.15 ppm prior to opening the system to atmosphere.
Recognizing this restriction, GPU has evaluated the techniques for reducing the Cl concentration in the RCS (presently about 2 pp.n) to comply with this stated requirement.
The conclusion of this evaluation, which
-. ~.
i is discussed below, is that it is impractical to remove Cl from the RCS wate r.
Metallurgical evidence also indicates a higher RCS Cl concentration can be safely tolerated.
One technique for Cl removal uses a cation resin to first remove sodium.
This drops the pH of the water to 5.5 shifting the boric acid equilibrium point such that Cl will be removed selectively by an anion resin. This option would require the generation of at least 10 6x6 liners for Cl-J removal, (30,000 gallon batch size) assuming SDS effluent cesium and strontium concentrations are less than 0.01 u C1/ml.
These influent requirements are l
necessary to permit shallow land burial of this waste as cesium and strontium are removed by the cation resin.
If the SDS effluent cesium and strontium l
concentrations are greater than 0.01 u C1/ml, more liners would be required.
This processed water would require chemical adjustment by the readdition of sodium hydroxide to increase the pH above 7.5 prior to reinjection into the RCS.
4 i
Another Cl removal technique uses enough anion resin to remove both the boron and the Cl. This option would require the generation of at least 20 6x6 liners (15,000 gallon batch size). Because of the large amount of dissolved boron in the RCS water, the SDS effluent cesium and strontium concentrations are of less concern because an anion specific resin is used.
l As in the sodium removal option, the processed water would also require l
chemical adjustment prior to reinjection into the RG. Enough boric acid i
would have to be added to bring the boron concentration back to at least 3500 i
ppm, our present procedural lower limit for boron concentration in the RCS.
i i t
i Another option evaluated involved laboratory testing of a low chloride anion J
resin (IRN-78 obtained from Rohm & Haas) to determine if Cl could be selectively removed from RCS water without removing a significant quantity of To simulate SDS processing conditions, a 20 mi test column was boron.
prepared and the flow rate was set at 2 ml/ min. (10 minute residence time).
A simulated RCS solution containing 1000 ppm sodium, approximately 3800 ppm The results coron, and 1.8 ppm Cl was prepared and fed through the column.
of this test indicated that although some Cl was selectively removed, the selectivity coefficient is not high enough to make the process practical; I
Cl breakthrougn was greater than 50% after only 30 bed volumes.
Additionally, although no significant amount of boron was removed after 25 bed volumes, nearly 300 pounds of boric acid would be removed before the resin Therefore, the selectivity coefficient for Cl-becomes boron saturated.
removal is not high enough to make the operation practical, and significant t
amounts of-boric acid would have to be added to bring the boron concentration back to required concentrations.
l t
Each of the options discussed above requires the use of organic anion resins.
i Based on tha experience obtained during the processing of Auxiliary Building l
water, transuranic (TRU) material was removed by these resins with an average Additionally, samples sent off-site during SOS operation DF of 1000.
indicated that zeolite resin does not remove transuranics.
Therefore, it is reasonable to assume that during RCS processing the TRU present in the RCS l
water will pass through the zeolites and would be taken up by the organic l
resins used for Cl removal. :
4 Three RCS samples taken on March 29, 1979, August 14, 1980 and December 28, 1981 have been analyzed for TRU content.
The results of the first two RCS samples showed 7x10-5 and 6x10- u Ci/ml of Pu and 240hu. The 239 December 18, 1981 sample showed 1.4x10-6 Ci/ml total TRJ.
The disparity in analysis results demonstrates the uncertainty in mobile TRU content in the RCS. Assuming total deposition on EPICOR liners, significant quantities of TRU would be adsorbed on the resins.
The loading would require careful monitoring in light of the present burial ground requirements for each of the three licensed commercial burial grounds which limits TRU content of radioactive waste to 10 n C1/gm. Proposed 10 CFR Part 61 contains this same TRU limit. GPU does not have the analytical capability to support an on-line operation where continuous TRU monitoring is required.
Therefore in order to assure that non-disposable waste is not produced, processing which will generate TRU type waste is being deferred.
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I SAFETY EVALUATION JJSTIFYING CHANGE
Background
fn the present operating mode the RCS is being maintained in a full pressurized condition with the Standby Pressure Control (SPC) System.
The temperature is approximately 100oF, with the RCS chemistry specifications currently required by the Recovery Operations Plan as follows:
pH
> 7.5 Baron, ppm 3000-4500 Hydrogen, scc /KO
> 5 0xygen, ppm max 0.1 A hydrazine residual is maintained in the fresh makeup provided by the SPC system as a means of oxygen control.
The results of a detailed analysis of the RCS water is given in Table 1.
MATERIALS WMPAT;.81LITY General Table 2 contains a general list of the materials of construction in the RCS, It can be seen that the two basic classes of materials of interest are Inconel and stainless steel. For these two materials there are various corrosion concerns related to the chemistry of the coolant.
Austenitic Stainless Steels The austenitic stainless steels are susceptible to damage by pitting in aqueous chloride environments. They are also susceptible to stress corrosion cracking in environments containing oxygen, chlorides or sulfur singularly or in combination. These are corrosion mechanisms discussed in the next two subsections.
Pitting Pitting is usually associated with stagnant conditions, such as a liquid in a tank or liquid trapped in a low part if an inactive pipe system.
An extended initiation period is usually required before visible pits appear.
This period ranges from months to years, depending both on the specific metal and the corrosive media. Once started, however, a pit usually penetrates the metal at an ever-increasing rate.
Pitting is insidious because it is a localized form of corrosion and penetration can occur rapidly.
In addition, pits tend to undermine or undercut the surface as they grow.I l
Most pitting failures are caused by chloride and chlorine-containing lons.
Oxidizing metal ions with chlorides are aggressive in this regard.
Some materials are more resistant to pitting than others.
The addition of 2%
molybdenum and 2-5% more nickel to Type 304 produces Type 316 stainless steel, and results in a significant increase in resistance to pitting.2,3 The l
1 L
additions apparently result in a more protective or more stable passive surface oxides.
These two materials behave so differently that Type 304 is considered unsuitable for high chloride services, but Type 316 is sometimes used.4 Stress Corrosion Cracking Stress corrosion cracking is probably the most widely encountered form of corrosion in aqueous chloride environments at temperatures above 90 C (175 F).5 In general, it has been found that lowering the pH of chloride solutions or increasing the chloride concentration accelerates the cracking rate.2,3,5,6,7 Increasing the chloride content greatly reduces the stress at which cracking has been observed in stainless steels at 180 C (356 F).0
At higher temperatures, cracking has been observed to occur at lower chloride ion concentration.10 Chlorine has been shown to produce stress corrosion cracking of, stressed, sensitized stainless steel at ambient temperatures.11,12' In borated water salutions the stress corrosion cracking of sensitized and non-sensitized Type 304 and 316 stainless steel.with chlorides has been observed to be strongly pH 12, 13 12 dependent At Westinghouse, tests were conducted in solutions containing 2500 ppm B with temperature profiles simulating a loss of coolant accident (approximately 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 280 F and then gradual cooldown to 140 F in approximately 17 days and then maintained at 140 F for test duration up to 16 months).
The chloride ranged from 0.1 ppm to 500 ppm and the pH was varied from 4.5 to 10 at 77 F with NaOH. As illustrated by Figure 1, stress corrosion cracking was observed at low chloride and low pH valuas. However no stress corrosion cracking as noted to occur for 12-16 montns in any of the 20 sets of test specimens at pH values of 8.0, 9.3, and 10.0 and chloride levels of 100 ppm and higher.
Oak Ridge flational Laboratory (ORNL), tests were also conducted with borated water solutions containing 3000 ppm B and temperatures simulating a loss of coolant accident (1 day at 285 F, 7 days at 212 F, and 2 months at 180 F).
Stress corrosion cracking was noted to occur with as low as 5 ppm chlorides at 4.5 pH and 77 F.
No cracking was observed at a pH of 9.3 and 100 ppm enloride.
Type 304 and 316 stainless steel have been found to be susceptible to stress corrosion in tne presence of oxygen in an aqueous medium, high residual stresses, and some sensitization of the metal adjacent to welds, in the heat-affected-zone (HAZ), but not outside this area where sensitization has not taken place.14,15,16 In BWR experience and some laboratory tests in simulated BWd environments,I no cracks have been reported in Type 304L or in Type 316 (non-sensitized) stainless steel. General Electric found that the Type 316 is more resistant to Intergranular Stress Corrosion Cracking (IGSCC) than Type 304.14 In general, if other environmental factors remain constant, stress corrosion cracking of sensitized stainless steel tend to increase with temperature.,
, 9, 0,21 1
I For IGSCC to occur in sensitized stainless steel in high purity water, an oxidizing agent must be present. A reduction of dissolved oxygen from 10 ppm to 0.2 ppm has increased the time to initiate cracking a hundred fold.8,14,15,22 Other variables that affect the' susceptibility of sensitized stainless steel to IGSCC include: prior cold work, crevices in which environments become acidic, surface grind marks, the presence of H0 which acts as an oxidizing agent, and decreasing the pH below 22 7.14,15 Tne threshold strain (strain below which crack initiation from pits does not occur) increases as pH increases above 7 and is significantly higher for Type 316 than for Type 304.23 Reduced forms of sulfur have been shown to cause intergranular stress corrosion cracking of sensitized austenitic stainless steels and have been related to acidic conditions because the reduced forms are more likely to exist in acidic conditions.25,26 One example is thionic acids which has been noted in the stress corrosion cracking of sensitized stainless steel in the petroleum industry.27,28 The levels of reduced sulfur at which the stress corrosion cracking has occurred has varied.
In tests with similar borated water environments, sensitized stainless steel was shown to crack with thiosulfate ions (S 0 =) in the low ppm range whereas cracking did not 23 occur with higher levels of thiosulfate ions.29,30 I
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Investigations of the pipe cracking incidents at TMI-l and ANO-1 have indicated that oxygen, chlorides and reduced sulfur may have been involved, sometimes singularly and sometimes in combination.
The solutions involved were stagnant and borated with the pH on the acid side. As a followup to these investigations tests are being conducted at B&W's Alliance Research Center sponsored by the Electric Power Research Institute (EPRI) to provide information on the relations between sulfur, oxygen and chloride in the stress corrosion cracking phenomenon.30 Table 3 contains a list of the tests performed and presents a general summary of the results to date.
The most significant results have been the indicated synergistic effect between sulfur (in the S 0 form) and chlorides in low concentrations.
Although pH 23 effects have not been investigated extensively, there was a general indication of a slight reduction of cracking tendency when the pH was elevated from approximately 5 to approximately 6.
Inconel-600 High nickel alloys are susceptible to stress corrosion cracking in aqueous environments containing sulfur in reduced form.25 As with sensitized austenitic stainless steels many cases can be attributed to the presence of thionic acids.25 Until late 1981, there were no known or reported cases or such cracking occurring in the environment of a reactor coolant system.
In November 1981 leaks developed in the TMI-l steam generator tubes.
Metallurgical examinations of the tube specimens removed from the steam generators indicated that the leaks resulted from cracks that were primary-side (reactor coolant) initiated.
The examinations further indicateo that sulfur may have been associated with the cause. At the time the leaks developed, the RCS was at a low pressure or depressurized condition and the temperature was at about 100 F.
RCS analysis indicated the following: pH
~ 5.5 at 77 F, boron (as boric acid) ~2400 ppm, lithium-7 ~0.8 ppm.
Around the period the leaks occurred the RCS was in both a filled and partially filled condition.
Analyses of RCS samples taken sometime after the leaks developed showed that low levels of sulfur were present. However, from these analysis results and other reviews it was not possible to deteImine what the actual sulfur levels were, or the sulfur form at the time the leaks occurred.
Thus it is not possible at this time to specifically relate the role of sulfur in the Inconel cracking noted in TMI-1.
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APPLICABILITY TO TMI-2 RCS The following is a discussion of the applicability of the foregoing to the TMI-2 RCS.
pH, A basic pH has been shown to be an important ingredient in producirg an environment in which stainless steel is less susceptible to stress corrosion cracking related to the preserce of chlorides, or reduced sulfur, or oxygen or combinations of these.
This has been additionally applicable to the stress corrosion of Inconel 600 in a reduced sulfur environment. Therefore, it is important to maintain a basic pH during the cleanup period.
This position is supported by NACE Standard RP-01-70 which is a document that contains
" Recommended Practices for Protection of Austenitic Stainless Steel in Refineries Against Stress Corrosion Cracking by use of Neutralizing Solutions During Shutdown."27 In this document it is stated, "The National Association of Corrosion Engineers issues this Standard in conformity to the best current technology regarding the specific subject." The standard deals with protection from attack by both chlorides and reduced sulfur.
The pH should be > 7.5 at 77 F but higher values would be better because the susceptibility of the materials to stress corrosion cracking decreases with increasing pH.
However, the benefits of increasing the pH by specific values cannot be accurately assessed and significant increases in pH may be difficult.
~]
to achieve as indicated in Table 4.
This table shows the amount of sodium required to produce pH values of 7.5, 8.0, 8.5 and 9.0 for solutions containing 3500, 4000, 4500 ppm B.
It can be seen for example, that going from a pH of 7.5 to 8.0, the sodium concentration has to increase by a factor of about 2.
It is important, however, to maintain the pH > 7.5 at 77 F to provide assurance that the pH is on the basic side.
Chlorides Pitting of austenitic stainless steels usually occurs in stagnant conditions and under deposits.
The RCS may be at stagnant conditions for long periods of time and may contain large amounts of surface deposits from the debris released during the March 29, 1979 incident. Such pitting has the potential of occurring with significant amounts of chloride in the reactor coolant.
Concentrating mechanisms can cause the chloride to increase in localized areas so that the higher the chloride is in the RCS the more likely that it will increase by these mechanisms and ultimately cause pittirg.
The basic pH and low temperatures and pressures during the cleanup period will produce favorable conditions to minimize the susceptibility of austentitic stainless steel to stress corrosion cracking. However, consideration must be given to the subsequent operations after the cleanup is complete.
The RCS contains crevice areas in the reactor coolant pumps, piping theImal sleeves, and in the l
pressurizer into which the chlorides may tend to migrate and remain until the RCS is restored to operations at high temperatures and pressures.
It may not be possible to clean the crevices or to detect the presence of high chloride concentrations in crevices.
1 i
3 The RCS chloride has ranged from the present levels of approximately 1 to 2 ppa to the levels of 4-6 ppm during the periods after the Maren 28, 1979 incident.33 For the first six months after the incident weekly analyses
).
Indicated that the chloride average was approximately 4.2 ppm.
In view of the prior RCS chloride levels and the possible synergistic effects between sulfur and cnloride identified in the EPRI studies, the chlorides in the RCS should be limited to 5 ppm maximum during the cleanup period.
i Sulfur i
Where sulfur has been involved in the stress corrosion cracking of austenitic stainless steel and Inconel-600 or high nickel alloys it has been attributed to the sulfur being in the reduced form with acidic conditions. Hence, the basic conditions in the RCS should provide a favorable environment from a standpoint of the sulfur considerations. Recent analyses of RCS samples have indicated the presence of 7.6 ppm sulfate (S0
- ) which is an oxidized 4
i form of sulfur. No reduced sulfur was detected therefore it could be stated that the concern about reduced sulfur has diminished; however, as discussed in the next suosection on oxygen there is a possibility that the sulfate could be i
converted into reduced species if the RCS is subjected to a strong reducing environment.
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. Oxygen Dissolved oxygen has been known to cause intergranular stress corrosion cracking of sensitized austenitic stainless steels, but the temperatures, where these failures occured were significantly higher than those that will exist during RCS cleanup. Oxygen is also related to the chloride stress corrosion cracking of austenitic stainless steels, but again at higher temperatures. With a pH > 7.5 at 77 F and chloride < 5 ppm operations with saturated dissolved oxygen is considered acceptable. It would be desirable, however, to keep the oxygen levels as low as possible.
The normal or practical method would be to use hydrazine to scavenge the oxygen; but for the hydrazine to be effective either the temperature of the water must be increased or the hydrazine-oxygen molar ratio must be increased significantly.
j Hydrazine is a strong reducing agent and as such is capable of converting oxidized sulfur species to reduced sulfur species. At least one service failure of Inconel-600 material is thought to have been caused by the interaction of sodium sulfite with hydrazine (both compounds are oxygen scavengers) to form polythionic acid which led to intergranular attack.24 Furthermore, there is evidence that sodium sulfate will also react with hydrazine to form sodium sulfite.25 Then, the sulfite can react with more hydrazine to again form polythionic acids, leading to metal degradation.
Thus, it would appear that large concentrations of hydrazine should be avoided and that the potential side effects from using hydrazine are of more concern than having dissolved oxygen in the RCS during the cleanup. Consequently we do not intend to add hydrazine to the water returned to the RCS.
However, the dissolved oxygen levels should be reduced by using nitrogen in gas spaces associated with the cleanup, such as in the RCBT's.
EXPERIENCE AND TESTING In order to further support the proposed RCS chemistry specifications a metallurgical investigation of a flow jumper used in the SDS, which has been in service from July 1981 to March 1982, was performed. The material being examined is a portion of a Type 304 stainless steel welded 2" Tee with socket welded Type 304 stainless steel nipples.
This metallurgical investigation consisted of metallography and dye penetrant examination which were performed on the interior and exterior of the tee and the piping, particularly in the crevice regions and weld heat affected zones.
Also, an ASTM-A-262 Practice A test was conducted to ascertain if the heat affected zones were susceptible to intergranular corrosion.
Findings of metallographic and dye penetrant examinations were:
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Slight intergranular corrosion at the interior of the piping extending less than one grain in depth (<.001")
(2)
No crevice corrosion at the austenitic stainless steel materials i.e.,
fitting, piping or weld metal (3)
Similar depth of grain boundary corrosion in the base metal and heat affected zone of the piping (4)
No relevant dye penetrant indications ASTM-A-262 Practice A revealed some ditches at grain boundaries, but no one grain completely surrounded.
These metallographic observations indicate that these materials (fitting and piping) would have a low susceptibility to intergranular attack. The conclusion drawn from the findings discussed above is that the materials tested have not been deteriorated significantly by corrosion.
Additionally the service this jumper has seen consists of approximately 265,000 gallons of air saturated fluid, whose chemistry is shown below, passing through the jumper:
Maximum Minimum Average Typical RCS pu 8.50
- 5. 51 7.92 7.7 Conductivity (a mho/cm) 1750 465 1262 3000 Sodium (ppm) 630 125 366 1000 Baron (ppm) 1353 811 1099 3700 Chlorides (ppm) 30 7.1 21 1-2 Sulfate (ppm) 50 14 30 7.6 In comparision the RCS has basically had the chemistry parameters listed in column four above for (approximately) the past three years.
Even with the proposed chemistry changes the RCS will have less severe chemical conditions.
Therefore, as the material of construction of this jumper is characteristically similar to the material of concern in the RCS, the successful test results from the metallurgical investigation of the SDS jumper, following the subjection of that material to high oxygen and chloride water is_ considered to be verification that delivering oxygen saturated water at less than or equal to 5 ppm chlorides to the RCS is acceptable.
SUMMARY
AND CONCLUSIONS Based on the foregoing discussion it is concluded that 4
i 1.
A basic pH is an important factor in reducing the susceptibility of austenitic stainless steels and Inconel-600 to stress corrosion I
cracking. Hence, the pH must be maintained at > 7.5 at 77 F at all times during the cleanup period.
2.
Tests have indicated possible synergistic effects between reduced sulfur and chlorides in the stress corrosion cracking of austenitic, stainless i
steels with sulfur ions and chloride ion in the low parts per million l
range.
In view of this effect and the prior RCS chloride levels, the RCS chloride should be limited to 5 ppm maximum during the cleanup period.
3.
Operations with saturated dissolved oxygen conditions are considered acceptable with pH > 7.5 at 77 F and chlorides < 5 ppm.
It would be possible to use hydrazine to control oxygen; however, hydrazine is a strong reducing agent and in high concentrations has the capability of l
converting oxidized sulfur form to the reduced species which are capable of causing the stress corrosion cracking of both sensitized austenitic stainless steel and Inconel 600. On this basis the use of hydrazine to control oxygen during the cleanup period should be avoided. i - --
TABLE 1 RCS CHEMISTRY 1)
Total Solution Assay Analysis Result pH
- 7. 7 + 0.1 Boron (ppm) 3700 + 10 Sodium (ppm) 900 + 30 3H (u Ci/ml) 0.034 + 0.003 134Cs (u C1/ml) 1.6 + 0.1 137 s C1/ml) 15.3 + 0.7 C
90 r (u(u S
Ci/ml) 16 + I 144Ce (u Ci/ml)
<0.I8 Gross Beta (u Ci/ml) 49 + 1.5 Transuranics (u C1/ml) 1,4 x 10-6 + 6 x 10-7 Gross Alpha (u C1/ml)
< l. 5 x 10 2)
Filterable Material (Greater Than 0.45 Micron) 134Cs (u Ci/ml) 0.019 + 0.0005 137Cs (u C1/ml) 0.175 7 0.005 Transuranics (p C1/ml) 9.0 x 10-7 + 2.3 x 10-7 90Sr (a Ci/ml) 0.32 + 0.02-144Ce (u C1/ml)
< 3.2 3 3)
Anion Analysis (By Ion Chromatography)
Fluoride (ppm)
Formaldehyde Interference (audeo
[
as preservative)
Chloride (mm)
.794 Phosphate (ppm)
<0.005 I
Nitrate (ppm)
.167 Sulfate (ppm) 7.616 Sulfite (ppm)
<0.005 Thiosulfate (ppm)
<0.05 4)
Cation Analysis (By Atomic Absorption)
Nickel (ppb) 21 (10 soluble, 11 insoluble)*
Chromium (ppb) 80 (13 soluble, 67 insoluble)*
Iron (ppb) 3118 (342 soluble, 2776 insoluble)*
Filtered thru 0.45 micron millipore filter 5.
Additional Analyses (all results in PPM)*
Analysis Result Aluminum 0.19 Antimony
<0.009 Bismuth
<0.03 Cadmium
<0.03 Copper
<0.009 Germanium
<0.009 Indium
<0.09 Lead
<0.03 Lithium 1.8 Magnesium 0.007 Manganese 0.028 Mercury
<0.09 Molybdenum 0.13 Niobium
<0.03 Phosphorus
< 0. 3 Potassium 1.7 Silicon 0.23 Silver
<0.03 Tin
<0.03 Titanium
<0.03 Tungsten
< 0. 3 Vanadium
<0.009 Zinc
< 0. 3 Zirconium
<0.03
- These analyses are the results of additional ion chromatography, atomic absorption and emission spectrography measurements of RCS samples.
TABLE 2 MATERIALS OF CONSTRUCTION The main materials of construction in the reactor coolant system
- in contact with the reactor coolant are:
MATERIAL CONDITION Type 304 Sensitized & Non-sensitized Type 304L Non-sensitized Type 316 Sensitized & Non-sensitized Type 316L Non-sensitized Inconel 600 Sensitized Inconel 600 Sensitized Weldmetal Type 308 Sensitized & Non-sensitized Weldmetal The Type 308 weldmetal is used as the cladding for the reactor vessel, main RCS piping, pressurizer and steam generator plenums.
Inconel 600 is the steam generator tube material, while Inconel 600 weldmetal is the cladding for the steam generator tube sheets. Most of the RCS pipe connection safe ends are also constructed of Inconel 600.
Type 304 is used for many items such as the RC pump parts, CRDM parts, RCS small piping and interconnecting piping to the RCS from auxiliary systems and equipment. Type 316 is used in such areas as the pressurizer spray line and pressurizer surge line.
Type 304L and Type 316L are only used in selected special areas.
Not including reactor internals, fuel components, instruments, etc.
TABLE 3 Status of EPRI Project RP 1841-1:
" Pipe Cracking In Low Pressure PWR Borated Water Systems" Test Program MATERIAL:
Sensitized Type 304 Stainless Steel ENVIRONMENT:
1000, 5000, 13000 ppm H 803 with or without 1 ppm 3
LiOH, pH4.6 to 6.0 CONTAMINANTS:
1, 10 ppm CL-1, 10, 100, 1000 ppm F-1, 10, 100, 1000 ppm S 0 =
23 TEMPERATURE:
1500F (650C)
SPECIMEN:
Plastically Deformed Stressed Strips TYPE OF TEST: Electrochemical (Anodic Polarization)
Conventional (0 pen Circuit)
Major Results Low F or CL will not cause cracks Low S 02 3 = will cause cracks Low CL-Plus $ 03 will cause cracks more readily 2
High H 803 concentrations reduce or inhibit cracking o
3 Addition of LiOH reduces cracking o
Absence of oxygen does not prevent S 0j cracking o
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Table 4 PH Adjustment pH g+ ppm 3500 ppm B 7.5 660 8.0 1300 8.5 2025 9.0 3050 4000 ppm B 7.5 800 8.0 1560 8.5 2350 9.0 3500 4500 ppm B 7.5 1000 8.0 1860 8.5 2730 9.0 3970 1 i l
1 0 0 0 _,.__.
MATERIAL - TYPE 304SS t
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i REFERENCES 1.
M. G. Fontana and N. D. Greene, Corrosion Engineering, 1967.
2.
K. C. Thomas, H. M. Ferrari, and R. S. Allio, " Stress Corrosion of Type 304 Stainless Steel in Chloride Environments," Corrosion, 20, p. 89T, 1964.
3.
H. R. Copson, "Effect on Composition on Stress Corrosion-Cracking of Some Alloys Containing Nickel, " Physical Metallurgy of Stress Corrosion Fracture, ed. T. N. Rhodin, Interscience, 1959, p. 247.
4.
J. A. Beavers, A. K. Agrawal, and W. E. Berry, " Corrosion Related Failures in Power Plant Condensers," presented at Corrosion /81-Conference, April 1981, Toronto, Canada.
S.
S. W. Dean, Jr., Stress Corrosion-New Approaches, ASTM STP 610, " Review of Recent Studies on the Mechanism of SCC in Austenitic Stainless Steels," 1976.
6.
L. R. Scharfstein and W. F. Brindley, Corrosion, 14, 1958, 588t.
7.
P. Soo, " Analysis of Structural Materials for LMFBR Coolant Boundary components - Materials Property Evaluations," WARD-3045T3-5,
{
Westinghouse Electric Corporation, November,1972.
8.
T. Shimose, A. Takamura & K. Shimogori, " Stress Corrosion Cracking of Austenitic Stainless Steel in Chloride Solutions," Trans. of the Japan Institute of Metals, 6, p. 83, 1965.
9.
S. Berg and S. Hendrikson, " Influence of Chloride Ion Concentration on the Stress Corrosion of Stainless Steels at Different Temperatures,"
TVF. Teknisk-Vetenskaplir Forshoning, V. 32, No. 3 (1961), pp. 145-151.
(Abstract in Battelle Tech. Review, July 1961, p. 700).
10.
J. F. Eckel, " Stress Corrosion Crack Nucleation and Growth in Austenitic Stainless Steels," Corrosion, Vol. 18, July 1962, pp. 270t-276t.
11.
H. A. Domain, " Weld Repair Procedures for Stainless Steel Piping in NSS Dalance of Plant Systems," Letter Report to K. E. Moore, Babcock &
Wilcox LR:79," 2438-03:01, February 18, 1980.
12.
D. D. Whyte and L. F. Picone, " Behavior of Austenitic Stainless Steel in Post Hypothetical Loss of Coolant Environment," WCAP-7798-L, Westinghouse Nuclear Systems, November 1971.
13.
J. C. Greiss and G. E. Creek, " Design Considerations of Reactor Containment Spray Systems - Part X," ORNL-TM-2412, May 1971.
14.
" Investigation and Evaluation of Stress-Corrosion Cracking in Piping of Light Water Reactor Plants," NUREG-0531, February 1979..
REFERENCES (cont'd) 15.
C. F. Cheng, "Inf.ergranular Stress-Assisted Corrosion Cracking of Austenit3c Alloys in Water-Cooled Nuclear Reactors," JNM, 56, 1975, pp.
11-33.
16.
S. P. Rideout, " Stress Corrosion Cracking of Type 3C4 Stainless Steel in High Purity Heavy Water," Proceedings of the Second International Congress on Metallic Corrosion, NACE, Houston, TX,1966, pp.159-171.
17.
A. J. Giannuzzi, " Studies on AISI Type-304 Stainless Steel Piping Weldments for Use in BWR' Application,: EPRI NP-944, General Electric, December 1978.
18.
T. P. Hoar and J. G. Hines, "The Stress-Corrosion Cracking of Austenitic Stainless Steels. Part I - Mechanism of the Process in Hot Magnesium Chloride Solutions,:
J. Iron and Steel' Inst. (Brit.), February 1956, pp. 124-143.
19.
A. S. Couper, " Testing Austenitic Stainless Steels for Modern Refinery Applications," Materials Protection 8_, No. 10, p. 17 (1969).
20.
H. Kohl, "A Contribution to the Examination of Stress-Corrosion Cracking of Austenitic Stainless Steels in Magnesium Chloride Solutions,"
Corrosion 23, No. 2, p.'39 (1967).
21.
E. L. White, W. E. Berry and W. K. Boyd. "The Influence of Combined Environmental Effects on Stress Corrosion Cracking of Welded Stainless Steel Piping," 3rd Quarterly Progress Report, EPRI RP-311-3, Battelle Columbus Laboratory, 1977.
22.
W. L. Clarke and G. M. Gordon, " Investigation of Stress Corrosion Cracking Susceptibility of Fe-N1-Cr Alloys in Nuclear, Reactor Water Environments," Corrosion-NACE, Vol. 24, NO.1, January 1973, pp.1-12.
23.
D. Birchon and G. C. Booth, " Stress Corrosion Cracking of Eome Austenitic Steels as Affected by Surface Treatment and Water Composition," Proc. 2nd International Conf. on Met ' Corrosion 1963, NACE, New York, NY, pp. 33-36.
24.
W. E. Berry, W. N. Steigelmeyer, J. E. Slater, E. L. White and W. K.
Boyd, BMI Topical Report on Examination of Inconel /A0 Tubing from the A Steam Generator of the Palisades Nuclear Plant,tto the Consumers Company. July 11, 1970.
25.
G. J. Theus and R. W. Staehle, Review of Stress Corrosion and Hydrogen Embrittlement in the Austenitic Fe-Cr-Ni Alloys, Ed. R. W. Staehle, J.
Hothman, R. D. McCright and V. E. Slater, NACE 5, Pub. National Association of Corrosion Engineering, 1977.
s s.
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REFERENCES (cont'd) 26.
NACE Standard PR-01-70, Recommended Practice - Protection 'of Austenitic Stainless Steel in Refineries Against Stress Corrosion Cracking by Use of Neutralizing Solutions During Shutdown, National Association of Corrosion Engineers, October 1970.
27.
A. Dravnieks and C. H. Samans, American Petroleum Institute 3_7, 100 (1957).
28.
C. H. Samans, Corrosion 20, 256t (1964).
29.
R. S. Plascik, G. J. Theus and J. V. Monter, "The Effect of Cl, F,
and S 02 3 on the Corrosion Behavior of Sensitized Type 304 Stainless Steel in Borated Water," Babcock & Wilcox iPGD Report NPGD-TM-579, Lynchburg, VA (July 1981).
30.
J. V. Monter and G. J. Theus, unpublished work for EPRI Project RP-1841-1, " Pipe Cracking Experience in Low Pressure PWR Borated Water Systems."
f 31.
H. A. Domian and G. J. Theus, " Review of Pipe Cracking Experience in Low Pressure PWR Borated Water System," Topical Report for EPRI Project i
RP-1841-1, Babcock & Wilcox, Alliance Research Center Report LR:82:4859:01:01, Alliance, Ohio, February 1982.
32.
H. R. Copson, "An Appraisal of the Resistance to Stress-Corrosion Cracking of Iron-Nickel Chromium Alloys in Pressurized Water and Related Environments," paper presented at the Polytechnic Institute of Brooklyn Seminar on Corrosion in Nuclear and Conventional Power Plant Sytems, New York, NY, May 1969.
33.
J. H. Hicks, Compilation of Chemistry Results for TMI-2 Reactor Coolant System, Babcock & Wilcox NPGD Report NPGD-TM-557, Lynchburg, VA, (July 1980). _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _