ML20028D184
| ML20028D184 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 01/12/1983 |
| From: | Rothstein S CONSOLIDATED EDISON CO. OF NEW YORK, INC. |
| To: | |
| References | |
| ISSUANCES-SP, NUDOCS 8301170212 | |
| Download: ML20028D184 (98) | |
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Uhf0 UNITED STATES OF AMERICA tlUCLEAR REGULATORY COMMISSION *g3 'NI I4 Af f :10 ATOMIC SAFETY AND LICEllSING BOARD Before Administrative Judges:
James P. Gleason, Chairman Frederick J. Shon Dr. Oscar H. Paris
, __________________________________________x In the Matter of ) Docket Nos.
l COtiSOLIDATED EDISON COMPAtlY OF NEW YORK, ) 50-247-SP
! INC. (Indian Point, Unit No. 2) 50-286-SP
! )
POWER AUTHORITY OF THE STATE OF NEW YORK January 12, 1983 (Indian Point, Unit. No. 3) )
x j CON EDISON'S TESTIMONY OF SAMUEL ROTHSTEIN CONCERNING BOARD QUESTION 2.2.1 l
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ATTORtIEY FILING THIS DOCUMENT:
l Brent L. Brandenburg
(
CONSOLIDATED EDISON COMPANY l
OF tlEW YORK, INC. ,
i 4 Irving Place New York, New York (212) 460-4600 i
, 8301170212 830112 PDR ADOCK 05000247 T PDR 9 S0 3 =-
- s Table of Contents Page I. Introduction . . . . . . . . . . . . . . . . . 1 II. Steam Generator Description . . . . . . . . . 2 III. Corrosion Protection Program . . . . . . . . . 3 IV. Present Condition of Indian Point Unit 2 Steam Generators . . . . . . . . . . . 6 V. Applicability of Proposed Draft Steam Generator Generic Requirements ,
to Indian Point 2 . . . . . . . . . . . . . . 13 VI. Conclusion . . . . . . . . . . . . . . . . . . 27 l
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My name is Samuel Rothstein. I am the head of the Chemical e .o Metallurgical Engineering subsection in the Mechanical Studies section at Con Edison. I received a Bachelor's t
Degree in Chemistry from City College of New York in 1940 and have completed a large number of graduate courses in metallurgy at several universities. I have been employed at Con Edison i
j since 1971. During this time I have had responsibility for 1
the development of the Steam Generator Inspection Program for Indian Point Unit 2. A more detailed listing of my back-ground is appended to my testimony as Attachment SR-1.
I. INTRODUCTION
. The purpose of my testimony is to address Board Question 2.2.1 which reads as follows:
"Should any of the requirements proposed at the July 29, 1982 meeting of the NRC staff and members of the Steam Generators Owners Group (SGOG) be required for Indian Point Units 2 and/or 3, considering the risk of a steam generator tube rupture in this h.igh population area?"
1 The testimony is presented in two parts - the condition of the Indian Point Unit 2 Steam Generators, and a point by point discussion of draf t SGOG generic steam generator requirements proposed by the NRC sta f f at the July 29, 1982 meeting. A copy of the draft requirements proposed at that meeting is appended to this testimony as Attachment SR-2.
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II. STEAM GENERATOR DESCRIPTION In the Pressurized Water Reactor (PWR) system, the steam gen-1 erators isolate the radioactive reactor coolant from the non-radioactive steam cycle, and serve as the heat exchanger i
between the two systems. ,
The Westinghouse steam generators are vertical U-tube natural circulation evaporators and consist of two sections: 1) a heat exchange section with reactor coolant channel head, tube sheet and tubing, and 2) a steam separator section which includes the feedwater ring. The heat exchange section is a vertical shell and U-tube heat exchanger.
The Indian Point Unit 2 steam generators are Westinghouse Series "44", with a total heat transfer surface of l approximately 44,000 square feet. The heat transfer tubes I are Inconel 600 ( ASME SB 163, Alloy UNS N06600) and the support plates are carbon steel (ASME SA 285). There are four steam generators with 3,260 tubes and 6 support plates each. The tubes have a design outside diameter of 875 mils and wall thickness of 50 mils.
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' s During operation, high temperature, high pressure reactor cool-ant flows from the Reactor Vessel to the inlet side of the channel head at the bottom of the steam generator by way of the hot leg, enters through the inlet nozzle, flows through the l
U-tubes to the outlet side of the channel and exits the genera-tor through the outlet nozzle and flows back to the Reactor Vessel by way of the cold leg. The inlet and outlet channels are separated by a partition plate welded to the channel head and the tube sheet. On the secondary side of the steam genera-tors, feedwater enters the evaporator section of the steam gen-erator just above the top of the U-tubes through a feedwater i
ring. The water flows downward through an annulus between the tube bundle wrapper and the shell and then upward through the tube bundle where a portion of the water is converted to steam.
The steam / water mixture from the tube bundle passes through swirl vane separators and.a secondary moisture separator.
The moisture removed from the uteam is returned to the heat exchange section. The full load steam conditions at the outlet nozzle for Indian Point Unit 2 steam generators are a temperature of 505.5*F and a pressure of 705 psig.
Indian Point Unit 2 has been operating since 1973 and has oper-ated for approximately 38,000 f ull power hours. In this country,
- there are approximately 30 steam generators of the same model which collectively have accumulated over half a million full power hours of operation.
III. CORROSION PROTECTION PROGRAM I served as Con Edison's representative on two Electric Power Research Institute (EPRI) committees with (Ad Hoc Steam Generators, and Systems and Materials), which dealt with
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o s 1 steam generators. A Steam Generators Owners Group (SGOG) was formed under EPRI auspices to collectively study the potential for steam generator corrosion. Con Edison has participated in the activities of the Owners Group and I have been a member of the Group's Technical Advisory Committee.
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, In four plants, corrosion of the steam generators was so far
! advanced at the time of the organization of the Owners Group that they could derive little or no benefit from the various studies completed by the Group. Three of these plants have already replaced their steam generators. These are Surry 1 and 2 and Turkey Point 3. Turkey Point 4 is now in the process of replacing their steam generators. Two other plants, Point Beach 1 and Robinson have also committed to early replacement of their steam generators.
As a result of the studies completed by the Steam Generator Owners Group and the interchange of information among utilities operating nuclear power plants, utilities have become more aware of the causes of steam generator corrosion and corrective mea-sures that could be taken to minimize that corrosion.
The minimizing of corrosion is important because corrosion de-posits fill the' clearance space in the annuli between the tubes and the support plates, and then exert compressive forces on the tubing and non-uniform in-plane loadings on the remaining sup-port plate material. This results in deformation of the tubes (called " denting") and in-plane expansion and distortion of
l the support plates. In extreme cases the " denting" results in tube cracking in the region of maximum tube distortion.
At Con Edison an extensive program aimed at mitigating the effects of corrosion and minimizing corrosion rates was ini-tiated in 1977 and is continuing. This program, encompasses the steam generators as well as associated systems in the plant, and includes the following activities:
o Reduction of the average operating primary coolant system temperature.
o Initiation of Boric Acid treatment of steam generator feed-water.
o Implementation of soak and drain procedures for steam gen-erators during and upon startup from refueling / maintenance outages.
o Reduction of air in-leakage into secondary system water.
o Relocation of hydrazine injection point to turbine exhaust instead of condensate pump discharge.
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o Performance of corrosion product survey of secondary system water to identify the source of corrosion products.
o Installation of a feedwater make-up deaerator.
l r o Institution of a condenser examination program.
o Installation of instrumentation to provide early indication of condenser cooling water in-leakage.
I o Evaluation of the advisability of installation of condensate polishers.
o Evaluation of the potential effectiveness of high temperature filtration.
o Development of a technique for measuring tube shapes and
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j calculating strain (profilometry).
l o Replacement of high pressure feedwater heaters tubed with copper alloy tubing with heaters tubed with stainless steel.
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6-o Replacement of moisture separator / reheater copper alloy tube bundles with stainless steel tube bQndles.
o Evaluation of the advisability of reintroducing phosphate treatment of secondary system water.
o Revision of operating procedures to prevent operation with significant chloride concentration in steam genreator feed-water.
o Expansion of steam generator examination program to include extensive visual examination of the secondary side as well as to increase several fold the extent of eddy current examination of tubes.
IV. PRESENT CONDITION OF INDIAN POINT UNIT 2 STEAM GENERATORS A. Steam Generator Tube Examination Techniques In order to help in understanding the Indian Point Unit 2 Steam Generator Tube Examination Program, several tubing examination techniques will be descri, bed. Note that each technique is most appropriate for different conditions that may be suspected during steam generator tube examina-tions.
- 1. Eddy current. This technique utilizes a cylindrical probe, approximately 6" long, with a diameter slightly less than the inside diameter of the tube, on which are wound two separate coils. As the probe is passed through the tube being examined, high frequency current is passed through one coil. (Frequencies ranging from 10 KHz to 600 KHz are generally used) The high fre-quency current in the coil induces eddy currents in the
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i tube wall, which in turn induce high frequency current
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in the companion coil. The induced current is affected by discontinuities or defects in the tube wall, and is continuously compared to the initiating current. The change in induced current as compared to the initiating current is interpreted as a defect in the tubing.
Variations on this basic technique have been developed as the need arose as set forth below.
a) Conventional single-frequency eddy current. In l this technique, a single frequency initiating current is passed through one coil, and serves as the basis for comparison with the induced current in the companion coil on the probe. This technique i is most applicable to the detection of defects where there are no interfering signals.
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b) Conventional multifrequency eddy currer.t. In this l
technique, current at several frequencies is uti-l
! lized as the initiating current and passed through the " base" coil, and the induced current (also at several frequencies) in the companion coil is compared to it. The frequencies can be separated i
l l and recombined to eliminate unwanted signals.
l Therefore, this technique is most applicable where interfering signals are present.
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c) Absolute eddy current. In this technique two probes are used. One probe is used as described above in 1); a second probe is fixed inside a tube of known acceptable quality. The initiating current is passed through " base" coils in both probes. The induced
, current in the companion coil on the probe being l
passed through a tube being examined is compared to that in the companion coil in the fixed probe. This technique is most applicable in identifying defects that exhibit a gradually increasing effect on the tube wall, such as a gradual wall thinning.
l 2. Profilometry. In this technique, electro-mechanical sensors are used to measure the tube profile. These measurements are processed and fed to a computer, which t calculates strain in the tube. This technique is most i
applicable to dented tubes.
B. Indian Point Unit 2 Steam Generator Tube Examination Program The Steam Generator Tube Examination Program, as conducted most recently during the refueling and maintenance outage for Indian Point Unit 2 completed in December 1982 included the following examinations:
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- 1. Eddy current examination of steam generator tubing for defects and dents.
This examination included for each steam generator a minimum of 12% of the active tubes in the hot leg and l
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3% of the active tubes in the cold leg. The sampling included all the tubes in areas of the tube bundle where other utilities have reported tube degradation.
- 2. Eddy current examination of selected tubes for wall thinning in the crevice.
This examination included approximately 30 tubes in each of the four steam generators in the area considered to be most susceptible to wall thinning. Some utilities have reported thinning and cracking of tubes in the crevice between the tubes and the tube sheet.
- 3. Eddy current examination of selected tubes for pitting.
This examination included approximately 30 tubes in each of the four steam generators in the region considered to be most susceptible to pitting. Some utilities have reported pitting of tubes in the region between the tube sheet and the lowest support plate, i 4. Profilometry examination of selected tubes to determine the strain resulting from tube distortion due to dent-ing.
This examination included over 300 tubes on the hot leg side of the steam generators. Profilometry of cold leg tubes was not included because eddy current examination indicated that cold leg dents were generally smaller than hot leg dents i.e. the 610 mil diameter probes could pass easily.
- 5. Visual (photographic) examination of the flow slots in the support plates of each steam generator.
This examination included all support plates photo-graphically visible from the tube lane above the tube
, sheet (as accessed through the lower steam generator shell hand-holes) and the uppermost support plate in two steam generators (as accessed through the one inch inspection ports that were installed by Con Edison several years ago).
- 6. Visual examination, as thoroughly as practicable, of the lower secondary side of all steam generators.
This examination was accomplished by passing a televi-sion camera through the lower hand-hole along the tube lane between the hot and cold legs of the steam genera-tor in such a way that the camera could record observa-i tions down the lanes between columns of tubes, first on the hot leg side and then on the cold leg side.
C. Results of Steam Generator Tube Examinations Eddy current examinations indicated that the steam generator tubes were completely free of defects. There was no indi-cation of wall thinning in the crevices and there was no indication of pitting in any tube. Based on eddy current measurements, there was no significant change from the prior measurements either in the average dent size or in the maxi-mum dent size in the tubes in the steam generators.
The eddy current examination found that only forty tubes would not pass a 610 mil probe as a result of the deforma-tion caused by the buildup of corrosion products in the annulus between the tubes and the support plates. Although it had been determined by the NRC that 540 mil diameter was the lower limit of acceptability of steam generator tubes, 610 mil diameter was established as the plugging threshold as a conservatism against possible further changes in the tube during the following period of operation. These forty tubes were included in the group of tubes that were examined by profilometry for strain (the change in length per unit length, as a result of tube defr,Jmation). Of the forty, it was found that in 20 tubes, strain was acceptably low; that is, low enough so that the probability of stress corrosion attack during service is nil. Based on tube strain criteria mutually agreed upon by Con Edison and the NRC staff, these tubes were kept in service and the remaining 20 tubes were plugged.
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( Currently, out of the total of 13,040 tubes there are 491 tubes plugged in four steam generators. Of this number, 397 were plugged during construction and subsequent support plate sampling. The remaining 94 tubes have been plugged
! since initial operation in 1973. The number of tubes plugged in service at Indian Point Unit 2 is less than at any other plant with the same model steam generator.
Examination of the uppermost support plates revealed that there was no apparent distortion of the flow slots there.
Examination of the flow slots in the lower support plates, which were originally 2 3/4 inches wide, revealed small changes or no change in the amount of closure of the flow slots. The current closure varies from none, i.e. full 2 3/4 inches open, to approximately half closed. The rate of closure for the flow slot that exhibited the largest
- change was 0.045 inches per month. The rate of change, of the flow slot with the maximum cumulative closure was 0.020 inches per month. Both these values represent a decrease of approximately 30% from the rates determined in 1980 and com-pare very f avorably with the rate 0.120 inches per month ,
reported by Turkey Point in 1977. On average the flow slots had no measureable change in dimensions. The comparable
- average change in 1980 was 0.010 inches per month. This indicates that the overall rate of corrosion has decreased.
Based upon the results of the above examination, previous examinations and operating experience at Indian Point Unit 2, I conclude that the corrosion of the steam generators at Indian Point Unit 2 is essentially arrested; that is, the rate of change is hardly measureable. There is no pitting, cracking or other deterioration of any of the steam genera-tor tubes. Tubes that have been significantly deformed as a result of the accumulation of corrosion products between the tubes and the support plates (that is, dented) have l
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4 been preventively plugged and removed from service. Based on experiences at other plants as well as Indian Point Unit 2, it is improbable that any tubes with significant l deformation have not been examined. Examination of the secondary side of the steam generators failed to reveal the presence of any significant foreign objects.
V. APPLICABILITY OF PROPOSED DRAFT STEAM GENERATOR GENERIC REOUIREMENTS TO INDIAN POINT 2 The purpose of this section is to discuss the applicability to the Indian Point Unit 2 steam generators of the proposed draft steam generator generic requirements presented by the NRC staff at the July 29, 1982 meeting with members of the SGOG. The objective of the meeting was to solicit comments from industry
> regarding the proposed requirements. Some comments were offared at the meeting; other comments were forwarded by the affected utilities through the EPRI SGOG. All these comments are being considered by NRC at the present. In general, many of these proposed requirements are already being implemented at Indian Point Unit 2. In fact, some of these items had their origin at Indian Point Unit 2. A discussion of each proposed draf t generic requirement, as set forth in Attachment SR-2, with reference to its applicability to Indian Point Unit 2, is set forth below.
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- a. Prevention and Detection of Loose Parts and Foreign Objects A continuous, on-line monitoring system capable of monitor-
! ing the steam generator secondary side, as well as the pri-mary side, for loose parts and foreign objects was installed at Indian Point Unit 2 during the recently concluded 1982 fueling / maintenance outage. This system meets the guidance of Regulatory Guide 1.133. Furthermore, during the most recent (i.e. 1982) steam generator examination, the secondary side of the steam generators was examined using a television camera which was passed down the tube lane in
- such a way as to collect observations of the spaces or i
lanes between the columns of tubes. This examination demonstrated that there were no significant-loose parts or foreign objects in the steam generators.
Maintenance and Quality Assurance / Quality Control (QA/QC) procedures for steam generator primary and secondary side maintenance, repair and inspection operations are in effect and are reviewed continually and revised as necessary to ensure that an effective system exists to preclude intro-I duction of foreign objects into either the primary or the secondary side of the steam generator. The procedures in-clude (1) detailed accountability procedures for all tools and equipment used during an operation, (2) appropriate controls on possible foreign objects such as eye glasses and film badges, (3) cleanliness requirements, and (4)
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accountability procedures for components and parts removed from the Steam Generators (e.g., reassembly of cut and removed components).
- b. Stabilization and Monitoring of Degraded Tubes The only known progressive degradaticn mechanism occurring i
in the Indian Point Unit 2 steam generators is denting, the I progressive distortion of tubes due to the accumulation of corrosion products between the tubes and the support plates.
i l This fact has been pointed out in previous discussions with f the NRC Staff concerning the results of our steam generator examinations.
It is not known what the rate of this degrad,ation mechanism is after a tube is plugged. More than 25,000 tubes have been preventively plugged in steam generators in power plants all over the country as a result of the denting mechanism. The single incident ac Ginna was the only case ever reported where a previously plugged tube subsequently severed in service. This event was caused by a fairly large foreign object and probably would have happened even l if the tube was not plugged. Monitoring the continued degradation of such non-leaking, plugged tubes would not be very productive. Furthermore, examination of the steam generators at Indian Point Unit 2 demonstrated that there were no significant loose parts or foreign objects in the steam generators.
p--> m = ~---4, ~ s - 4 s .---" - --r- 3. m NA-- C A- ---- -m---1L +A-- ai;a * --J1 - - M In order to provide assurance that adjacent tubes are not damaged by a plugged degraded tube, it is Con Edison's practice to include the tubes surrounding a plugged tube in tae eddy current examination program. Damage to any of the surrounding tubes should become readily apparent long before tube rupture occurs.
- c. Inservice Inspection Program Con Edison has conducted extensive steam generator tube in-spections since the beginning of plant operation. These a inspections have generally exceeded existing requirements.
The requirements of the current Indian Point Unit 2 Techni-i cal Specification 4.13 for in-service examination of steam generator tubes exceeds the proposed draft generic steam generator requirements. The Indian Point Unit 2 Technical Specifications require each of the four steam generators to be examined not later than after 16 months of operation with a primary coolant temperature greater than 350*F, or not later than 20 calendar months from the date of restart after the previous examination, whichever comes first. The technical specifications also require that a minimum of 12%
i of the tubes in each steam generator hot leg be examined and a minimum 3% of the tubes of the steam generator cold leg be examined. Furthermore, the Technical Specifications address denting and define criteria for plugging tubes that are dented. The Technical Specifications also require re-porting within forty five days after completion of the l
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! examination except that a significant increase in the rate of denting or a significant change in steam generator con-dition requires immediate reporting. No such immediate reporting has ever been necessary at Indian Point Unit 2.
. d. Improved Eddy Current Techniques
,' The eddy current examination techniques to be applied to steam generators should be established by the operators on a plant-specif ic bas is. Different operating steam generators have different types of defects, which justify utilizing I
differing eddy current techniques. Wastage, or tube thin-ning, develops in tubes in steam generators which are fed with water treated with phosphates. Crevice cracking develops in tubes in steam generators which have a signifi-cant amount of experience with phosphate treatment. Pitting develops in tubes in steam generators which have had appre-i ciable in-leakage of cooling water or ion-exchange resins.
a The only degradation evident in the Indian Point Unit 2 -
steam generator tubing is denting, which is best detected and quantified by conventional single-frequency eddy current examination. When examinations for possible special prob-
- lems such as crevice cracking or pitting are conducted, other techniques are utilized as appropriate. For example, an absolute eddy current examination technique used for crevice cracking and a multi-frequency examination technique for pitting to ensure elimination of any unwanted copper signals. These are the latest techniques available.
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Wear or f retting has not been a problem at Indian Point Unit 2 and we see no reason to expect these problems because they are associated with the ' preheat' type steam aenerators.
Therefore, a simulated wear or fretting standard for Indian Point Unit 2 examinations is currently of no value.
j Con Edison believes that improvement in non-destructive i
testing techniques should be a continuing goal of the nuclear industry. Con Edison, through its participation in the Steam Generators Owners Group as well as other pro-jects funded by Con Edison, has supported the research and i development activities design'ed to improve steam generator ,
examination techniques. Con Edison believes that it is in its own interest to locate tube degradation as reliably as possible and that continued improvement in steam generator examination techniques can best proceed on a plant specific basis without additional generic requirements.
- e. Prim *.Ty to Secondary Leakage Limit The current Indian Point Unit 2 Technical Specification j 3.1.F already contains provisions which comply with and is more restrictive than this proposed requirement, namely, l that the Technical Specifications provide leakage limits consistent with the latest revision of the applicable Standard Technical Specifications. It should be noted that the leakage experience at Indian Point Unit 2 has been ex- I cellent.
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- f. Secondary Water Chemistry Program The Indian Point Unit 2 operating l'icense already contains a condition which requires a secondary water chemistry program.
A secondary water chemistry program has been in effect at Indian Point Unit 2 since initial operation. The current program requirements exceed those in the proposed draft requirements. The program is described in specific plant procedures. Indian Point Unit 2 Procedure IPC-S-012 (Revi-sion 6 now in effect) defines the non-radiological in-plant chemistry specifications, the sampling frequency and report-ing requirements, and Standard Operating Procedure (SOP) 8.2 (Revision 8 now in effect) defines the procedures for secondary plant chemistry control.
I was a member of the Steam Generator Owners Group Water Chemistry Guidelines Committee and participated in the pre-paration of the water chemistry guidelines. The guidelines do not " represent an industry consensus opinion for state-of-the-art secondary water chemistry control" [p. 27 of Attachment SR-2] but are, in fact, guidelines or goals for a water chemistry program designed to be adapted to specific plants after taking into consideration plant mechanical equipment and operating conditions.
Long before the guidelines were issued, Con Edison, on the basis of an Indian Point Unit 2 feedwater corrosion products l study, had taken steps to approach the limits now set in the
guidelines. For example, to reduce copper in the feedwater, arrangements were made to retube the moisture separator /re-heater bundles of copper-nickel tubing with type 439 stain-less steel tubing, and the copper-nickel tubed high pressure feedwater heaters to be replaced with heaters containing type 304 stainless steel tubing. Furthermore, the hydrazine admission point was changed from the condensate pump dis-charge to the turbine exhaust in order to further reduce oxygen in the feedwater. We have installed and are testing an experimental high temperature magnetic filter to evaluate the feasibility of further reducing corrosion products (iron oxide and copper oxide) in the feedwater.
On the recommendation of the steam generator manufacturer, Westinghouse, Con Edison initiated in 1978 and is continuing a boric acid treatment of secondary feedwater. Westinghouse laboratory tests have demonstrated that this boric acid treatment arrests corrosion of carbon steel and the result-ing tube denting in steam generators.
Additionally, to maintain high purity water in the steam generators, the steam generator feedwater is monitored at the first source of possible contamination, the main con-densers. To determine if there is cooling water in-leakage, the condensate is analyzed for the major chemical con-stituents of river water, chlorides and sodium, and is monitored for total dissolved solids by conductivity. A
sodium flame photometer continuously monitors the main condensate pump discharge and alarms in the unit control room if the sodium increases beyond 0.002 ppm. If the 1
river water sodium concentration were 1000 ppm, this alarm point would mean that there is a condenser leak of about 6 oz/ min (less than 1 cupful per minute) entering a condensate I
stream of about 3,000,000oz/ min (25,000gpmh.
- g. Condenser Inservice Inspection Program The Indian Point Unit 2 operating license does not contain a condition to require performance of condenser inservice examination. However, in-service examination of the con-densers is conducted regularly at Indian Point Unit 2 during refueling / maintenance outages in accordance with Con Edison Enginecting recommendations.
At Indian Point Unit 2, there are three condensers, each containing two sections, for a total of six condenser sections and twelve water boxes. There are approximately 72,000 admiralty tubes, 1" in diameter by 50 feet long.
The condenser tubes, tubesheets and waterboxes are visually examined, and a number of tubes, selected at random, are examined by eddy curgent techniques. During the recent 1982 outage, over 1500 tubes were selected for the eddy current examination; the smallest r. amber of tubes from a single section was 165. The sampling plan was such as to yield a statistically reliable evaluation of the entire condenser.
In addition, selected tubes are withdrawn from the condenser and destructively examined to confirm the results of the eddy current examinations. Additionally, as indicated in f.
above, there is a system for monitoring and detecting con-denser leakage.
The established Con Edison practice of condenser in-service examination exceeds that described in the draft proposed generic steam generator requirement. It is our opinion that it is essential for utilities to remain free to establish and modify the condenser in-service examination programs and maintenance plans as they deem necessary for their respec-tive plants because condensers and their service exposures vary so greatly from plant to plant.
- h. Upper Inspection Ports 1
At Indian Point Unit 2, two steam generators are equipped with one-inch inspection ports in the " hillside" (the tran-sition cone between the shell and the steam drum) above the uppermost support plate so that three flow slots in each of those two steam generators can be examined by fiber optics.
These inspection ports were installed by Con Edison in 1976.
The condition of the remaining two steam generators can be extrapolated f rom that of the two examined, as all four steam generators are exposed to the same environment. It is our position that these two inspection ports are adequate
for the steam generators at Indian Point Unit 2. Examina-tion of the inner row U-bend tubes via these inspection ports is not really significant because the first row of tubes, that is, the inner row of U-bends, were plugged during construction.
It has been the practice at Indian Point Unit 2 to examine support plate flow slots via the hand holes above the tube sheet in all four steam generators. This examination yields information regarding to the closure of flow slots in the support plates which gives some general overall appraisal of the corrosion taking place in the steam generators. Addi-tionally, eddy current examination will detect denting long before any effects are visible through an upper inspection port.
- i. Reactor Coolant System Pressure Control During a Steam Generator Tube Rupture The steam generator tube rupture procedure at Indian Point 2 is designed to:
- a. Minimize the releases of radioactive material by identifying and isolating the faulted steam gen-erator and by reducing RCS pressure below the steam generator safety valve settings.
- b. Establish capability to supply feedwater to all steam generators and to isolate feedwater to the i
faulted steam generator.
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- c. Maintain the ability to remove the necessary residual heat from the reactor through the intact steam generators via the condenser steam dump valves or atmospheric relief valves.
- d. Maintain the RCS in a subcooled state during the recovery.
- e. Prevent overflooding of the faulty steam gen-erator.
In this procedure, the operators are instructed to reduce and control RCS pressure by utilizing normal pressurizer spray if reactor coolant pumps (RCPs) are running, or a pressurizer PORV if RCPS are not running. The auxiliary pressurizer spray would only be used as a last contingency to reduce RCS pressure.
. In response to Item I.C.1 of NUREG-0737, the Westinghouse Owners Group (WOG), of which Con Edison is a member, has been developing generic emergency response guidelines for i
the spectrum of anticipated transients and accidents and i
various contincencies thereto.
At the present time, the WOG Procedures Subcommittee is preparing Revision 1 to the generic emergency response guidelines package. By guidance contained in NUREG-0737, Item I.C.1, and in the more recent Supplement 1 to NUREG-0737 (issued December 17, 1982), all licensees, including Con Edison, will be utilizing the complete revised package
of generic emergency response guidelines to modify plant -
specific procedures over the next several years. Thus, any new concepts factored into Revision 1 of the emergency
, response guidelines package will be examined for inclusion, if appropriate, in plant-specific procedures.
- j. Safety Injection Signal Reset In response to an NRC generic letter dated November 28,1978 and IE Bulletin No. 80-06, Con Edison performed a detailed study to assure the proper operation of control and protec-tion logic and circuitry upon resetting the safety injection (SI) signal. With regard to the specific concern raised at Ginna - that of automatic switchover of safety injection pump suction from the Boric Acid Storage Tanks (BAST) to the Refueling Water Storage Tank (RWST) - the Indian Point Unit 2 design is different. There is no automatic transfer of safety injection pumps from a BAST to the RWST. The l
BASTS are not used for safety injection at Indian Point Unit 2. Indian Point Unit 2 has a separate tank - Boron Injection Tank (BIT) - which is aligned in parallel with the RWST to the safety injection pump suction. An SI signal does provide automatic opening signals to the BIT discharge valves such that safety injection pump suction is preferentially from the BIT first. When the BIT reaches the low level set point the BIT discharge valves receive l an automatic closing signal to isolate the tank, thus l
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f permitting the safety injection pumps to now take suction from the RWST. Unlike the situation at Ginna, the BIT low level signal will demand the BIT discharge valves to l close regardless of whether the SI signal is present or has been reset.
- k. Containment Isolation and Reset i
In response to TMI NUREG-0578, Con Edison accomplished plant modifications which prohibit the reopening of containment isolation valves upon resetting of the containment isolation signal. As a result of the detailed study of engineered l
- safety features (ESP) safety injection signal reset refer-enced in item j. above, the Chemical and Volume Control Sys-I tem (CVCS) letdown orifice valve circuitry was also modified to prevent their automatic reopening upon safety injection /
containment isolation reset. In addition, when the pres-l surizer level control valve in the CVCS letdown closes on low pressurizer level at Indian Point Unit 2, the valve j circuitry is such that even if pressurizer level recovers, the operator must separately operate the valve control l
switch to the open position for the valve to reopen. Thus, 1
a path to the CVCS letdown relief valve is not automatically
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established upon pressurizer level recovery and containment 1
isolation reset and the relief of primary coolant to the pressurizer relief tank as occurred at Ginna would not occur i at Indian Point Unit 2.
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- 1. Standard Technical Specification Limit for Coolant Iodine Activity We do not feel that a direct application of the Standard Technical Specification provisions for Reactor Coolant Sys-tem specific activity is appropriate without further con-sideration of plant specific design features and operations.
The basis for this item discusses highly unlikely circum-stances and timeframes, and use of the proposed specific limits and surveillance frequencies may not be required to satisfy the intent of the specification. The bases for thc Standard Technical Specification itself in fact point to the conservatism of the values due to the absence of speci-fic site parameters from the staff evaluation. Thus, uni-form application of such overly conservative limitations without consideration of plant-specific features may result in the imposition of unnecessarily stringent requirements which may have no significant impact on public health and i
safety but may have an impact on normal plant operation and availability and could lead to unwarranted plant shutdowns and undue cycling of plant systems and challenges to safety systems.
VI. CONCLUSION l
On the basis of the foregoing, I conclude that a program gen-erally equivalent to - and in several instances exceeding - the proposed draft generic requirements presented at the July 29, 1982 meeting of the NRC staff and members of the SGOG is already in effect at Indian Point Unit 2.
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Con Edison personnel recognized the steam generator corrosion problem before substantial corrosion occurred, and pioneered the implementation of investigative, remedial and mitigating mea-sures such as:
Examination Techniques o Provision of inspection ports for uppermost support plate o Sampling of tubes and support plate segment from lowest
- support plate o Development of in-house eddy current examination capabilities o Development of condenser and feedwater heater examination procedures o Development of profilometry examination techniques Chemistry Control o Reduction in average primary temperature o Corrosion products surveys o Reduction of copper in feedwater o Reduction of oxygen in feedwater i
o Installation of sensitive analytical devices Mitigating Measures i
o Analytical studies of effects of corrosion products build-up in support plates o Development of steam generator chemical cleaning. technique.
o Implementation of boric acid treatment.
Participating in the Steam Generator Owners Group and personal contact with counterparts at other utilities, Con Edison per-sonnel have continuously been aware of developments in the area
{ . .
of the steam generator corrosion and regularly evaluate the applicability of experiences at other utilities to Indian Point Unit 2.
The actions relating to steam generators implemented at Indian Point Unit 2 are a result of the integration of careful examina-tion of the components, analysis of the plant data, and sound engineering judgement. The success of Con Edison programs is evidenced by the condition of the steam generators and their l
l performance. The small number of tubes (less than 4%) plugged 2
in the steam generators at Indian Point Unit 2 compares favor-ably with those at other utilities, especially when one considers that approximately 3% of the tubes were plugged during construc-tion before the plant went into service. Indian Point Unit 2 remains one of the few PWR plants that has not had a forced
- outage because of a tube leak. Furthermore, the rate of cor-rosion as measured by flow slot distortion or by tube denting is reduced to a rate that is hardly measureable.
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ATTACHMENT SR-1 i
Samuel Rothstein Chemical and Metallurciczi Encineer SPECIAL QUALIFICATIONS:
Over thirty years in applied metallurgy including selection of I
materials, fabrication of pressure vessels and piping, and studies of corrosion of materials.
EDUCATION:
B.S. - College of City of !!ew York - 1940 Graduate courses and seminars in metallurgy and associated subjects at: Brooklyn Polytechnic Institute, Columbia University, M.I.T., Pennsylvania State University, and University of Illinois. Professional Engineer, licensed in State of New York.
EXPERIENCE:
From 1971 Chemical and Metallurgical Engineer Mechanical Studies Section, Mechanical Engineering Dept., Consolidated Edison Co. of New York, N.Y.
Evaluation and specification of materials for use in nuclear and conventional power plant equipment and structures. Specification of testing and non-destructive examination of components and evaluation of results. Specification and control of welding i
procedures. Investigation and correction of problems and failures in materials.
1970- Consulting Metallurgist 1971 (Self-employed) New Hyde Park, N.Y.
1958- Chief Metallurgist i
1970 AMF Inc., York, Pa.
Evaluation and specification of fabrication pro-cesses, materials and surf ace finishes for use in industrial, space and military equipment. Monitoring metallurgical manufacturing processes. Investigation -
i and correction of problems and failures in materials.
1944- Materials Consultant 1958 Fairchild Camera & Instrument Corp., Syosset, L.I., N.Y.
Evaluation and specification of materials and finishes for use in military airborne equipment, i ,,
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' * " " *'"**w 'ea- ...we u.e , '*d*' v'Pr-Nve,y.,,,9gg ,
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Samuel Rothstein page 2 Consultant to engineering and quality control on materials testing and examination. Technical direc-tion of heat treating, plating and finishing opera-tions. Investigation and correction of materials and manufacturing problems and material failures.
1940- Instructor 1944 Air Forces Technical School, Biloxi, Miss.
Classroom instruction re: materials in aircraft and
- aircraft engines.
PROFESSIONAL ACTIVITIES:
American Society for Metals American Welding Society EEI - Metallurgy & Piping Task Force Metals Properties Council - Technical Advisory Committee and Subcommittees on Nuclear Materials, Pressure vessel Me tals and Fracture Toughness Listed in "American Men of Science" PCELICATIONS:
5 Years of Ion Exchance - Chemical Waste Treatment, Plating, Vol. 45, No, s, August, 1958 Gravity Gradient Stabilization System Antennae Structures, NASA 9596, Decem=er 1966 Materials Performance at Indian Point Nuclear Power Station, sympostum on Materials Performance 730301, in Operating Nucl . Me tallNuclear . , Vol . 19, Systems, USAEC Conference -
1973 (co-author)
Contributor of chapter (s):
ASME Handbook on Water Technology (in preparation) plus many others COPYRIGHTS:
r Calculator, Cetermination of Ms Point in Steel, 1946 .
PATENTS _(pending):
Tubing inspection device and tube plugging device
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4 ATTACHIEIEP SR-2 A'
SUMMARY
OF JULY 29, 1982 MEETING WITH STEAM GENERATOR OWNERS GROUP (SGOG) REGARDING PROPOSED GENERIC REQUIREMENTS On Thursday, July 29, 1982 the NRC staff met with representatives of the SGOG in Bethesda, Maryland for the purpose of discussing proposed addi-tional steam generator generic requirements. Copies of the slides used by the NRC staff, the information package distributed during the meeting and a list of the attendees are enclosed.
The staff described the ongoing program to develop additional requirements relate.d to steam generator integrity and the mitigation of the consequences of steam generator tube rupture (SGTR) accidents. The program is based on the staff's perception of the need to consider issues related to the reso-lution of the Unresolved Safety Issues A-3, A-4 and A-5 regarding steam generator tube integrity, the January 25, 1982 SGTR at the R.E. Ginna plant as discussed in NUREG-0909 and NUREG-0916, three previous domestic SGTR's i
as discussed in NUREG-0651 and plant specific operating experience including various degradation mechanisms, tube leaks and plugging history as discussed in NUREG-0886 and in various plant specific licensing actions.
The staff addressed the prnposed requirements, as set forth in the handout, as representing the staff's current views on the respective subjects. The staff identified the purpose of the meeting as an opportunity to present the proposed requirements and to solicit responses from the SGOG regarding the valus/ impact of the proposed requirements.
The meeting discussions consisted largely of the staff's presentation of the information contained in the attached slides and handout with a limited response from other attendees based on their having been first presented with a description of tne proposed re.quirements at the meeting. At the conclusion of the meeting, the SGOG indicated that they planned to offer a written response within about two months. This schedule was somewhat beyond the staff's desired schedule for the staff development of value/ impact consider-ations; therefore the staff and SGOG agreed to meet again in about three weeks to consider the status of the SGOG responses at that time.
hjh)dA Ro ert E. Martin Operating Reactors Assessment Branch Division of Licensing
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i l PURPOSE OF WFTING PRESENT PROPOSED REQUIREMENTS TO DBTAIN INDUSTRY FEEDBACK REl.ATIVE TO VALUE IMPACT, I
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.s BACKGROUND e UNRESOLVED SAFETY ISSUES, A-3, A-4, A-5 (1977) e GINNA SGTR (NUREG-0909 AND NUREG-0916) e PLANT SPECIFIC OPERATING EXPERIENCE DEGRADATION MECHANISMS, TUBE LEAKS PLUGGING, HISTORY, ETC, SUMMARIZED IN NUREG-0886 PLANT SPECIFIC LICENSING ACTIONS l
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- 1. PROPOSED REQUIREMENTS e STEAM GENERATOR INTEGRITY PREVENT / DETECT LOOSE PARTS / FOREIGN OBJECTS STABILIZE / MONITOR DEGRADED TUBES TUBE ISI PROGRAM IMPROVED ECT TECHNIQUES PRIMARY / SECONDARY LEAKAGE LIMITS SECONDARY WATER CHEMISTRY CONDENSER ISI PROGRAM UPPER INSPECTION PORTS e PLANT SYSTEMS RESPONSE RCS PRESSURE CONTROL DURING SGTR SI RESET l
CI RESET e RADIOLOGICAL CONSEQUENCES STS LIMIT FOR IODINE ACTIVITY I
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11.1 PREVENTION AND DETECTION OF LOOSE PARTS AND FOREIGN OBJECTS t
REQUIREMENT 4 S.G. SECONDARY SIDE INSPECTION ABOVE TUBESHEET OF ENTIRE PERIPHERY (AND TUBE LANE) FOR LOOSE PARTS, FOREIGN OBJECTS AND TUBE 0. D. DAMAGE.
e IMPROVE QA/QC PROCEDURES TO PRECLUDE INTRODUCTION OF FOREIGN OBJECTS INTO SG PRIMARY / SECONDARY SIDES.
9 INSTALL AND OPERATE SG LPMS ON PRIMARY AND SECONDARY SIDE IN CONFORMANCE WITH RG 1.133 GUIDANCE.
BASES e FOREIGN OBJECTS OR LOOSE PARTS DISCOVERED IN S.G. PRIMARY OR SECONDARY SIDES OF: PRAI RI E IS LAND 1, GINNA, ZIcti 1, NORTH ANNA 1, S AN ONOFRE 1, DAVIS-BESSE, RANCHO SECO, OCONEE 3, AND TURKEY POINT 4.
8 SIGNIFICANT TUBE DAMAGE FROM LOOSE PARTS AND FOREIGN OBJECTS HAS OCCURRED.
9 DEFICIENCIES IN QA/QC DURING SG INSPECTION AND MAINTENANCE
! ALLOWED UNDETECTED FOREIGN OBJECTS.
8 LPMS FOR SG COULD HAVE AVERTED THE TUBE RUPTURES AT PRAIRIE ISLAND AND GINNA AND PREVENTED TUBE DAMAGE AT OTHER UNITS WITH FOREIGN OBJECTS AND LOOSE PARTS.
9 LPMS CAPABLE OF DETECTING OBJECTS 11/4 La.
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l 11.2 STABILIZATION AND MONITORING OF DEGRADED TUBES REQUIREMENT S LICENSEES SHALL PREPARE AND SUBMIT A REPORT THAT:
IDENTIFIES PROGRESSIVE DEGRADATION MECHANISMS CURRENTLY PRESENT OR LIKELY TO OCCUR IN THEIR PLANT.
CONTAINS CRITERI A AND PROCEDURES FOR (1) MONITORING OF PLUGGED NON-LEAKING TUBES FOR WHICH RATES OF PROGRESSIVE DEGRADATION ARE UNPREDICTABLE, AND (2)
STABILIZATION OF DEGRADED TUBES WITH POTENTI AL FOR SEVERANCES AND DAMAGE TO ADJACENT TUBES.
BASES e PLUGGED TUBES CAN DEGRADE FURTHER AFTER PLUGGING.
8 PROGRESSIVE DEGRADATION OF CONCERN IS THAT POTENTI ALLY AFFECTING ENTIRE TUBE CIRCUMFERENCE (E.G., CIRCUMFERENTI AL FATIGUE CRACKS AND FRETTING WEAR DUE TO FLOW INDUCED VIBRATION).
8 LIMITED LEAKAGE PLUGS TO MONITOR RATE OF FRETTING WEAR HAVE BEEN USED AT RINGHALS-3 (SWEDEN) FOR MODEL D3 SG, e RECENTLY, LIMITED LEAKAGE PLUGS TO MONITOR POTENTI AL DEGRADATION '0F " LIVE" TUBES SURROUNDING DAMAGED TUBES WERE USED AT TURKEY POINT 4.
O CIRCUMFERENTI ALLY CRACKED TUBES IN 14TH AND 15TH TSP INSPEC-TION LANE REGIONS IN OTSG'S HAVE BEEN STABILIZED WITH SOLID RODS ATTACHED TO SOLID PLUGS.
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11.1 . TUBE ISI PROGRAM ITEM BASES e COLD LEG SIDE TO BE INCLUDED" e COLD LEG SIDE ALSO SUDJECT IN INSPECTION TO DEGRADATION e CURRENTLY ALLOWABLE MAX.
9 MAX. INSPECTION INTERVAL TO BEv 48 MOS. FOR EACH S.G. INTERVALS OF 80 TO 160 MOS.
EXCESSIVELY LONG SPECIAL SUBSETS OF TUBES MAY e TO ALLOW AVOIDANCE OF 9
BE DEFINED EXCESSIVE INSPECTION OF TUBES NOT EXPERIENCING DEGRADATION 9 IF >l DEFECTIVE OR >5% DEGRADED e TO ENSURE THAT NO MORE THAN TUBES EITHER: MAX. TOLERABLE NO. FAILED l
- DO 100% INSPECTION, OR TUBES GO UNDETECTED
- DO INSPECTION BASED ON STATISTICALLY DETERMINED l
SAMPLING PLAN e SURVEILLANCE OF DENTING l 9 ADD DENTING INSPECTIONS TO ISI NECESSARY TO PREVENT SCC PROGRAM 9 TUBE INSPECTIONS TO BE CONDUCTED 6 EVEN SMALL LEAKS MAY INDICATI NEW PHENOMENA OR ACCELERATED IN RESPONSE TO REPAIR OF ANY LEAKS DEGRADATION l
e REQUIRED TO IMPLEMENT l e DENTING ACCEPTANCE LIMITS TO BE SURVEILLANCE OF DENTING INCLUDED IN TS 0 SAMPLING REQUIREMENTS e REPORT INSPECTION RESULTS To NRC PRIOR TO OPERATION IF RESULTS NECESSITATE REVI'SIONS TO I EXCEED PLUGGING LIMITS REPORTING REQUIREMENTS l
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- o 11.4 IMPROVED EDDY CURRENT TECHNIQUES REQUIREMENT 4 USE ECT OR DATA EVALUATION TECHNIQUES FOR SG ISI THAT ELIMINATE UNWANTED SIGNAL INTERFERENCES (E.G., TSP, l DENTING).
9 USE EC PROBES WITH ABSOLUTE AND DIFFERENTI AL INSPECTION C AP ABI LITY.
9 INCLUDE DIFFERENTI AL AND ABSOLUTE DATA IN EC OVERALL DATA EVALUATION PROGRAM.
9 IN ADDITION TO THE SECTION XI STANDARD USE A SIMULATED WEAR CALIBRATION STANDARD TO ENSURE A CONSERVATIVE INTER-l PRETATION OF SIGNALS FROM POSSIBLE WEAR OR FRETTING TYPE l
FLAWS.
BASES
- e LAB AND FIELD EXPERIENCE DEMONSTRATE SUPERIORITY OF MULTIPLE ECT TO ELIMINATE. UNWANTED SIGNAL INTERFERENCES.
e ECT IN ABSOLUTE MODE IN ADDITION TO DIFFERENTI AL MODE IMPROVES DEFECT DETECTION AND INTERPRETATION CAPABILITIES.
O WEAR DEFECTS GENERALLY DETECTED ON ABSOLUTE CHANNELS BUT MAY NOT PRODUCE SIGNALS ON DIFFERENTIAL CHANNELS.
l WEAR CALIBRATION STANDARD CONSIDERED NECESSARY.
4 THE TUBE WHICH RUPTURED AT GINNA EXHIBITED NO DIFFERENTI AL ,
SIGNAL DURING PREVIOUS ECT OF TUBE IN APRIL 1981. THIS TUBE DID EXHIBIT ABSOLUTE INDICATION INTERPRETABLE AS
<20% USING SECTION XI CALIBRATION STANDARDS, AND >40%
USING WEAR CALIBRATION STANDARD.
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II.5 PRIMARY TO SECONDARY LEAKAGE LIMIT REQUIREMENT ,
0 REVISE TECH SPECS FOR PRIMARY TO SECONDARY LEAK RATE LIMITS CONSISTENT WITH APPLICABLE STS.
BASES l
I e STS PRIMARY TO SECONDARY LEAK RATE LIMITS BASED ON:
1 GPM TOTAL SG LEAKAGE LIMITS RESTRICTS DOSE TO SMALL FRACTION OF 10 CFR PART 100 FOR SGTR OR MSLB.
I 500 GPD (0.34 GPM) LEAKAGE LIMIT /SG MAINTAINS TUBE !
O PRIMARY TO SECONDARY LEAK RATE LIMITS INDICATE:
l PRESENCE AND/OR RATE OF TUBE DEGRADATION.
WHEN SHUTDOWN, ISI AND CORRECTIVE ACTIONS ARE REQUIRED.
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II.7 SECONDARY WATER CHEMISTRY PROGRAM REQUI REMENT e A REQUIREMENT FOR A SECONDARY WATER CHEMISTRY PROGRAM TO MINIMIZE SG TUBE DEGRADATION SHALL BE SPECIFIED IN LICENSE CONDITIONS.
9 THE PROGRAM SHALL BE DEFINED IN SPECIFIC PLANT PROCEDURES BUT NOT SPECIFICALLY INCLUDED IN THE LICENSE.
e THE PROGRAM SHALL ADDRESS MEASURES TO MINIMIZE SG l CORROSION (I . E. , MATERI ALS SELECTI'ON, CHEMISTRY LIMITS l AND CONTROL METHODS, CORRECTIVE ACTIONS FOR OUT OF SPEC CONDITIONS).
9 REVISED SRP 5.4.2.1 PROVIDES STAFF REVIEW CRITERI A AND INCORPORATES "PWR SECONDARY WATER CHEMISTRY GUIDELINES" 0F SEPTEMBER 1981 PREPARED BY THE SGOG.
8 OPERATING PLANTS WHICH ARE SHUTDOWN TO EFFECT STEAM GENERATOR REPAIRS AS A CONSEQUENCE OF CORROSION WILL BE REQUIRED TO COMMIT TO THE REVISED WATER CHEMISTRY GUIDELINES PRIOR TO RESTART.
I BASES S IMPROVED SECONDARY WATER CHEMISTRY IS RECOGNIZED BY BOTH INDUSTRY AND NRC AS IMPORTANT IN REDUCING SG MATERIALS CORROSION.
O THIS PROGRAM WILL ASSURE UNIFORMITY, CONSISTENCY AND REDUCE SG REPAIR AND OTHER ACTIVITIES RESULTING IN OCCUPATIONAL EXPOSURE AND THE POTENTI AL FOR RELEASES TO THE ENVIRONMENT.
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II.8 CONDENSER INSERVICE INSPECTION PROGRAM REQUIREMENT e EXCEEDANCE OF SECONDARY WATER CHEMISTRY LIMITS WHICH SHOULD RESULT IN POWER REDUCTIONS TWICE PER QUARTER DUE ,
TO CONDENSER LEAKAGE, REQUIRES A LICENSE CONDITION (SIMILAR TO II.7) THAT COMMITS TO PERFORM CONDENSER ISI.
9 THE CONDENSER ISI PROGRAM SHALL BE INCLUDED IN THE PL' ANT OPERATING PROCEDURES.
! 8 OPERATING PLANTS WHICH ARE SHUTDOWN TO EFFECT STEAM GENERATOR REPAIRS AS A CONSEQUENCE OF CORROSION WILL BE REQUIRED TO COMMIT TO THE REVISED' CONDENSER PROGRAM PRIOR TO RESTART.
BASES e CONDENSER INTESRITY IS ESSENTI AL TO MAINTENANCE OF GOOD WATER CHEMISTRY.
O CONDENSER OPERATING EXPERIENCE (EPRI-NP-481) SHOWS THAT AIR AND WATER INLEAKAGE CAN CAUSE DEGRADATION OF SG TUBES.
O CONDENSER ISI IS REQUIRED ONLY IF THERE ARE REPEATED INDICATIONS THAT SATISFACTORY SECONDARY WATER CHEMISTRY CANNOT BE MAINTAINED.
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II.9 UPPER INSPECTION PORTS REQUIREMENT e PLANTS WITH U-TUBE SG'S LICENSED AFTER JANUARY 1,1983 SHALL INSTALL UPPER INSPECTION PORTS TO ENABLE VISUAL INSPECTION OF UPPER TSP AND INNER R0W U-BEND TUBES.
0 UPPER INSPECTION PORT INSTALLATION FOR OPERATING PLANTS WILL EE EVALUATED ON . CASE-BY-CASE BAS IS.
BASES S SG'S GENERALLY HAVE ONLY LOWER INSPECTION PORTS.
O PLANTS HAVE INSTALLED UPPER PORTS (AT UPPER TSP) WHICH ENABLES EVALUATION OF DENTING IN UPPER PART OF SG, FACILITATES TUBE REMOVAL FOR EXAMINATION, AND ALLOWS MONITORING OF UPPER TSP FLOW SLOT HOURGLASSING.
8 DUE TO IMPACT OF EXTENDED OUTAGES AND ALARA CONSIDERATIONS, THE NEED FOR BACKFIT TO ANY OPERATING UNIT WILL BE BASED ON CASE-BY-CASE REVIEWS OF THE SG OPERATING EXPERIENCE.
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111.1.1 RCS PRESSURE CONTROL DURING A SGTR REQUIREMENT e DETERMINE OPTIMAL MEANS OF CONTROLLING AND REDUCIt!G PRESSURE EMPHASIZING USE OF EXISTING EQUIPMENT.
9 OPTIMIZE PROCEDURES, TECHNIQUES AND SYSTEMS.
9 CONSIDER USAGE OF PORV AND AUXILI ARY SPRAY SYSTEMS.
9 OBJECTIVES: MINIMIZE LEAKAGE, MAXIMIZE PRESSURE CONTROL, MINIMIZE VOIDS IN RCS.
BASES S FOUR SGTR'S HAVE DEMONSTRATED DIFFICULTY IN MANAGING RCS PRESSURE.
G WITH LOSS OF PRESSURIZER SPRAY (RCP TRIP OR LOOP) RCS DEPRESSURIZATION IS MORE DIFFICULT.
O PRESSURE CONTROL WITH PORV LOSES COOLANT AND MAY RESULT IN VOID FORMATION THUS FURTHER COMPLICATING PRESSURE CONTROL.
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1 11I.1.3.1 SAFETY INJECTION SIGNAL RESET REQUIREMENT s
8 REVIEW LOGIC FOR ESF EQUIPMENT TO MINIMIZE LOSS l '0F FUNCTION UPON RESET OF SI.
8 EXAMPLE: CONSIDER SWITCHOVER OF SI PUMP SUCTION FROM BAST TO RWST INDEPENDENT OF SI RESET.
BASES S NEED TO PREVENT LOSS OF SI PUMP FUNCTION.
8 GINNA DESIGN POSSIBLY IMPROVED BY MAKING SWITCHOVER DEPENDENT ONLY ON BAST LEVEL, NOT ON SI RESET STATUS.
111.1.3.2 CONTAINMENT. ISOLATION AND RESET REQUIREMENT e REVIEW AND EVALUATE RESPONSE OF LETDOWN SYSTEM TO CI AND RESET SIGNdLS.
BASES e TO PRECLUDE UNNECESSARY RELEASES OF REACTOR COOLANT FOLLOWING RESET OF CI.
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V.1.4 STANDARD TECHNICAL SPECIFICATION LIMIT FOR COOLANT 10 DINE ACTIVITY REQUIREMENT 9 PLANT TECH SPECS FOR COOLANT ACTIVITY LIMITS THAT DIFFER IN IODINE LIMITS OR SURVEILLANCE REQUIREMENTS FROM THE STS SHALL INCORPORATE THE STS REQUIREMENTS.
O PLANTS WITH LOW LEAD HPSI PUMPS THAT DO NOT HAVE IODINE LIMITS EQUAL TO STS VALUES WILL BE REQUIRED TO IMPLEMENT THE REDUCED IODINE TECHNICAL SPECIFICATIONS REQUIRED FOR GINNA.
BASES S SOME PLANTS DO NOT HAVE LIMITS ON RADIOIODINE BUT LIMIT GAMMA ACTIVITY. TOTAL COOLANT ACTIVITY COULD REMAIN BELOW SHUTDOWi! VALUE WHILE RADICIODINE LEVELS COULD BE HIGH. IODINE SPIKING MUST BE ACCOMODATED AND CONTROLLED WITH SURVEILLANCE PROVISIONS.
9 THE STS INCORPORATE DOSE EQUIVALENT IODINE CONCENTRATIONS FOR ALL PWR'S THAT (1) HAVE APPROPRIATE CONSERVATIVE LIMITS (2) ACCOMODATE AND CONTROL IODINE SPIKING AND (3) HAS ADEQUATE SURVEILLANCE FOR PRIMARY AND SECONDARY C00LANTS.
9 IMPLEMENTATION OF ABOVE REQUIREMENTS PROVIDES ASSURANCE THAT WITH STEAM GENERATOR TUBE RUPTURE EVENTS, THE RADIOLOGICAL CONSEQUENCES SHOULD BE LESS THAN STAFF GUIDELINES.
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.- e s NRC PROPOSED ACTIONS e STEAM GENERATOR INTEGRITY
- TUBE SLEEVING GUIDANCE ON DESIGN, INSTALLATION AND INSPECTION.
e PLANT SYSTEMS RFSPONSE SG OVERFILL POTENTI AL AND CONSEQUENCES TO BE FURTHER EVALUATED.
- PRESSURIZED THERMAL SHOCK PROGRAM, TAP A-49, TO CONSIDER -
IMPROVED ACCIDENT MONITORING (REG. GUIDE 1.97) IMPLEMENTATION WILL ADDRESS ASPECTS OF GINNA SGTR.
- REACTOR VESSEL INVENTORY MEASUREMENT (TMI TAP II.F.2,
" INSTRUMENTATION FOR DETECTION OF INADEQUATE CORE COOLING")
IMPLEMENTATION WOULD IMPROVE MONITORING OF BUBBLE IN R.V. HEAD.
e liUf1AN FACTORS CONSIDERATION RCP TRIP (TM1 TAP II.K.3.5) IMPLEMENTATION SHOULD PROVIDE CONTINUED FORCED RCR FLOW THROUGH DESIGN BASIS SGTR.
CONTROL ROOM DESIGN REVIEW PROGRAM (TMI TAP I.D.1) TO CONSIDER GINNA SGTR EXPERIENCE.
PROCEDURES FOR TRANSIENTS AND ACCIDENTS PROGRAM (TMI TAP 1.C.1) i TO CONSIDER GINNA SGTR AND OTHER SGTR EXPERIENCES.
e RADIOLOGICAL CONSEQUENCES REASSESS CONSEQUENCES OF SGTR.
REEVALUATE SGTR DESIGN BASIS EVENT.
SECONDARY SYSTEM ISOLATION.
e NRC ORGANIZATION RESPONSE INCLUDES NRC STAFF ACTIONS TO IMPROVE RESPONSE OF NRC TEAMS TO AN EVENT.
INCLUDES NRC STAFF ACTIONS TO IMPLEMENT REQUIREMENTS OF ONGOING PROGRAMS.
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[,,.f 'lj NUCLEAR REGULATORY COMMISSION W ASHINGTON. D. C. 20555
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~JUL 2 21982 MEMORANDUM FOR: Gus C. Lainas, Assistant Director for Safety Assessment Division of Licensing FROM: Thomas A. Ippolito, Chief Operating Reactors Assessment Branch Division of Licensing
SUBJECT:
FORTHCOMING MEETING WITH STEAM GENERATOR WNERS GROUP - PROPOSED STEAM GENERATOR GENERIC REQUIREMENTS Date & Time: July 29,1982 10:30 a.m. - 5:00 p.m.
Location: Phillips Building, P-118 Bethesda, MD Purposa: To discuss the value/ impact assessment of the draft NRC report "NRC Requirements Concerning Steam Generator Tube Degradation and Rupture Events (Including resolution of USI's A-3, A-4, and A-5)"
in accordance with the attached agenda.
l Parti.ci pan ts : NRC D. Eisenhut, R. Mattson, S. Hanauer, R. Vollmer, R. Baer, R. Ramirez, G. Lainas , T. Ippolito.
T. Marsh, J. Strosnider, J. Moorehouse(SAI).
l SGOG A. Schmidt, L. White, P. Santoro, R. Acosta, R. McCredy, B. Snow, A. Curtis AIF A. Bivins EPRI i S. Gre3n N.. 'h- f dd, i Thoma . Ippolito, Chief Operating Reactors Assessment Branch Division of Licensing
Attachment:
As Stated
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. . .. ATTACHMENT i
AGENDA .
I. Introduction II. Proposed Licensee Requirements
- 1. Ste m Generator Integrity Prevention and Detection of Loose Parts or Foreign Objects Stabilization and Monitoring of Degraded Tubes Inservice Inspection Program l - Improved Eddy Current Techniques Primary to Secondary Leakage Secondary Water Chemistry Program Condenser Inservice Inspection Program Upper Inspection Ports
- 2. Plant Systems Response Reactor Coolant System Pressure Control During A SGTR Safety Injection Signal Reset Containraent Isolation and Reset
- 3. Human Factors Consideration None l 4. Radiological Consequences Standard Technical Specification Limit for Coolant Iodine Activity
- 5. Organizational Response None III. NRC Proposed Actions
- 1. Steam Generator Integrity Steam Generator Tube Sleeves 2 Plant Systems Response Steam Generator Overfill PORV Operability Pressurized Thermal Shock Improved Accident Monitoring Reactor Vessel Inventory Measurement
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- 3. Human Factors Consideration -
- Requirement on Reactor Coolant Pump Trip
- Rotary Switch Functional Identification
- Indicator Lights Burned Out
- Inconsistent Terminology
- Fe.argency Operation Procedures Improvement
- 4. Radiological Consequences
- Reassessment of Radiological Consequences Following a Postulated Steam Generator Tube Rupture Event
,- Reevaluation of SGTR Design Basis Event
- Secondary System Isolation
! - Review of Ventilation Intakes
- Collection of Snow Samples 1 5. Organizational Response
- Interactions with Regional Base Teams by the NRC Executive Team
- NRC Site Team
- Familiarization with NRC Response Plan Alternate Evacuation Routes and Sites
- Deescalation of Emergency Classification l
Offsite Dose Assessment 1
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HANDOUTS FOR JULY 29,1982 MEETING 4'
fl.1 Preven 21on and Detection of Loose Par 2s and F@ reign Objec2s Requirement Loose parts and foreign objects in steam generators shall be detected
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and prevented by performing inspections, improving quality assurance procedures , and monitoring" for loose parts as follows :
- 1. Steam generators shall be inspected on the entire periphery of the secondary side including the tube lane for purposes of identifying loose parts, foreign objects on the tubesheet and peripheral tube 0.D. damage just above the tubesheet. An appropriate optical device should be used (e.g., mini-tv camera ). For PWR OL applicants, such inspections shall be part of the preservice inspection. Licensees shall perform inspections (a) at the next planned outage for eddy curx nt testing of steam generator tubes, and the, eafter, (b) after any secondary side modification or repairs to steam generator internals, (c) when flaw indications are found in the free span portion ~ of peripheral tubes unless it has been reasonably estab-lished that the indications did not result from damage by a loose part or foreign objects. Requirement II.l.l(a) shall be performed until requirement 11.1.3 has been implemented.
Requirements II.l.l(b) and (c) shall continue to apply.
- 2. Quality assurance procedures for steam generator primary and secondary side maintenance, repairs, and inspection operations shall be reviewed and revised as necessary to ensure that an effective system exists to preclude introduction of foreign objects into either the primary or secondary side of the steam generator. This effort should apply to licensee quality assurance / quality control procedures when major components are opened. As a minimum, such procedures shall include DD AL"I
_. .. ___ _.. . _ . . _ . . . . ~ . .._
. . .m w (1) detailed , auntability procedures for all ,ols and equipment used during an operation, (2) appropriate controls on foreign objects such as eye glasses and film badges, (3) cleanliness requirements, and (4) accountability procedures for components and parts removed from the intemals of major components (e.g., reassembly of cut and removed components) .
- 3. All pressurized water reactors shall have installed and operational a loose parts monitoring systen (LPMS) capable of monitoring the steam generator secondary side, as well as the primary side.
The LPMS shall confonn to Regulatory Guide 1.133. Sufficient sensors shall be provided in acoustically coupled regions of the steam generator to ensure adequate LPMS sensitivity for detection of I
loose parts in the secondary side and the primary channel head.
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l Bases -
The bases for the secondary side inspection requirements and the improved quality assurance procedures is that the existing inspection methods and practices and material accountability controls have not proven sufficiently effective in ensuring that loose parts and foreign objects were identified and removed prior to startup.
i For example, the accountability controls in use at Ginna during the removal / modification of the downcomer resistance plate in 1975 were ineffective in determining that parts of the plate were left in the secondary side of the steam generator. Deficiencies included j (1) failure to perform a post maintenance accountability inspection of the removed resistance plate to account for all pieces, (2) failure to determine that an adequate barrier existed to preclude material dropping into the, steam generator, and (3) failure to perform adequate post maintenance inspection of the secondary side 2
DDAET
_m_ _ - _ _ _ __ __ _ _ . . _ _ . _ _ _ _ _ . _ _ _ _ _ . _ . . _ _ _ _ _ . . _ _ _ _ _
', of the steam gen ;or for foreign parts. Foreig ajects or loose parts have also been found in the steam generators at Zion 1. Prairie Island 1, North Anna 1. San Onofre 1, Davis Besse Rancho Seco, Oconee 3, and Turkey Point 4 The bases for recommending secundary side peripheral visual inspections also incluries the need to ensure that degraded conditions on the outer diameter of peripheral tubes such as may be caused by loose parts or foreign objects and support plate defomation have been adequately Wentified.
The bases for the recomendation to install a loose parts monitoring system is the observation of the damage done to operating generators by loose parts, which most likely cc !1d have been detected at an early stage had an adequate LPMS been in operation.
These operating experiences are sumarized below.
During the Ginna post-event activity, a number of foreign objects were found in the secondary side of the B-steam generator. The largest object appeared to be part of the steam generator down-comer flow resistance orifice plate which had been cut and removed cluring a steam generator modification in 1975. This large foreign 1
object most probably initiated the damage that led to the tube
- rupture. Post rupture examination revealed that severe damage 1
had occurred to 26 tubes in the periphery of B-steam generator.
The damage to these tubes was 50 extensive as to warrant removal by the licensee to prevent damage to sound tubes. In addition, portions of two fractured tubes were found skewed between the tube i
bundle and the steam generator shell; they were subsequently removed. Foreign objects were found in A-steam generator although no tube damage attributable to these objects occurred.
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l 3 noaET
7 _ _ - - -
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On October ,1979, a tube rupture developea in SG "A" of Prairie Island th h I while the plant was operating at full power. The licensee estimated the leak rate at about 390 gal / min. Visual _
and fiber optic inspections performed subsequent to the tube rupture incident revealed that the tube at Row 4, Column 1, ruptured about 3 in. above the tube sheet. The rupture was a classic:1 tube burst with a " fish mouth" opening about 1-1/2 in.
I long with a maximum width of about 0.5 in. The rupture break l edges were observed to be worn to a " knife edge." The tubes in adjacent positions (Row 3, Column 1, and Row 2 Column 1) also showed signs of wear. All wear marks and the rupture were on the outer peripheral side of the tube bundle at approximately the same elevation. A steel coil spring, 8.5 in. long,1.25 in. in diameter, and of 3/32 in, wire diameter was found lying on the l tube sheet adjacent to the defective tubes. One end of the spring was wedged between the tube sheet and a flow blocking device (the flow blocking device diverts flow away from the open tube lane and into the tube bundle) and the other end was free to move.
A visible wear pattern on the tube sheet indicated that the spring had moved back and forth during plant operation.
It is understood that Ginna and Prairie Island Units 1 and 2 previously had loose parts monitoring systems which were later removed due to frequent false alarms, which resulted in a loss of confidence in the LPMS by those plants. The staff believes that if the LPE had remained operable, the foreign objects might have been detected and removed and thus would have averted the tube rupture events.
MAFT
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. .- On Febru 25, 1982, while preparing for fy current testing of the 18 steam generator, the Zion 1 station personnel discovered 3 pieces of a hinge about 30 inches long and 2 inches wide in the channel head plenum area of the steam generator. These hinge fragments were later determined to be from an aluminum nozzle cover left in the 1D steam generator during tube testing in Ma rci. 1931. The aluminum cover is believed to have dissolved during reactor operation. There were two stainless steel hinges for the cover. One hinge section was found bent, but in one piece, in the ID steam generator. The other hinge section was found in 3 pieces in the 18 steam generator, which the licensee attributed to being caused by reverse flow in mid-February 1982 when the reactor coolant pumps A and D were shut down. Severe damage to over 1100 protruding tube ends on the inlet plenum of ID steam generator was due to the loose parts; extensive repairs were required. The licensee has indicated that loose parts monitoring signals and low flow transmitter deviations were observed during startup of Unit i following the April 1981 outage. An analysis by licensee's consultant at that time concluded that the loose part signals and flow deviations did not represent a problem for continuad safe operation of the plant. Had a proper procedure been following when loose parts had been detected and confirmed, the damage might have been avoided or mitigated.
To ilhstrate the sensitivity of LPMS, North Anna Unit 1 in a l report to the NRC dated May 1,1980, stated that acoustic analysis of the single event alanns indicated a loose part ooject located j in the secondary side of Steam Generator "B" weighing 4 ounces or 1
less. A 12 day outage (May 24 to June 4) allowed the licensee to open up SG "B" and inspect for loose parts. On May 29,1980 the l 5 Umi a
, , licenscF'1und an object in SG "B" apprc stely 1-1/2 inches long and 3/8 inches in diameter and estimated the weight to be 4 ounces or less. The licensee retrieved the object. More recently, the same plant shutdown on 5/17/82 due to Loose-Parts-Monitoring (LPM) signals. A Westinghouse acoustic monitoring team arrived on-site on 5/17/82 for analyses of the noise profiles. Loose parts were subsequently recovered from SG's "A" and "C" and were identified as control rod guide tube support pin nuts. These nuts have caused peening damage to the tube ends and tube sheets in both steam generators. An assessment of the damage is currently being performed.
Regulatory Guide 1.133 as referenced in Section 4.4 of NUREG-0800 provides guidelines regarding the LPMS system sensitivity and operating procedures. The staff concludes that if proper LPMS system calibration and alert level setting are performed by taking into account the background noise, false alarms can be minimized.
The sensors located on a steam generator in conformance with the guidelines of the Regulatory Guide would be capable of detecting loose parts weighing over 1/4 pounds in both the primary and secondary sides of the steam generator. A sufficient number of sensors placed on the acoustically coupled regions to provide broad coverage could increase the system sensitivity in detecting loose parts in the secondary side.
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s 88.2 Stabilization and Monitoring of Degraded Tubes Requirenent Licensee's shall develop criteria and procedures for plugging tubt which contain provisions fpr (1) the monitoring of further degradation in plugged non-leaking tubes for which the rate of further degrao6 tion cannot be reliably predicted, and (2) the stabilization of degraded tubes that may be subjected to progressive degradation mechanisms having the potential to cause severance of the tube and consequent damage to adjacent tubes.
Licensees shall prepare and submit a report containing, in addition to the information discussed above, an identification of all progres-sive degradation mechanisms presently occurring or likely to occur in their plant. The criteria in the report shall enable a determination of the licensee's bases for providing or not providing monitoring capability or stabilization for tubes plugged in the past as well as those to be plugged in the future.
Bases The basis for this requirement is that a plugged tube may degrade further after plugging such that it can become completely severed i and subsequently cause damage to adjscent tubes. The magnitude of this concern is indicated by the presence of over 20,000 plugged tubes out of a total tube population size of about 1.1 million. The most important types of degradation, in this regard, are those which can potentially affect the entire circumference of the tube.
Some of the more obvious examples are fatigue induced circumferential cracking and fretting wear from ficw induced vibration. The require-ment would alleviate the problem either by requiring the monitoring l
7 l .
- ~~ .m of the plugged tube's integrity so as to provide a warning of further degradation prior to severance of the tube or, by requiring ,
stabilization which would prevent severance or prevent severe tubes from interacting with neighbortng tubes. Several operating plant experiences which constitute part of the basis for this concern are discussed below.
The implementation of techniques, beyond the current conventional inservice inspection practices, to monitor the integrity of plugged tubes is thought by the staff to be less important for well under-stood and predictable degradation mechanisms than it is for r.awly encountered or unpredictable degradation mechanisms. An example of a recently encountered degradation mechanism which may benefit from monitoring is the tube fretting wear due to flow induced vibration l in the preheater section of Westinghouse Model D steam generators in ;
the Swedish Ringhals 3 plant, the Spanish Alamaraz 1 plant and the domestic McGuire 1 plant. Such wear has lead to a tube leak in the Ringhals 3 plant and all three plants are operating generally at no more than 50 percent power pending the development of improved feedwater inlet distribution hardware. The Ringhals 3 plant operators have chosen to install limited leakage plugs in tubes requiring plugging.
Plant operators currently feel that the tube wear rate and modes of plant operation causing excessive wear are well defined. However the use of the limited leakage plugs is intended to provide an earlier indication than of accelerated tube wear. The use of might otherwise be gained limited leakage plugs would also appear to be of interest in cases where damage has been sustained by peripheral tubes due to foreign objects (e.g., Ginna) and there is uncertainty as to the continued integrity of the nlugged tube.
The implementation of techniques to stabilize tubes becomes more important in cases where the potential for complete and/or rapid ..
circumferential cracking exists. Such degradation mechanisms may be driven solely by flow induced Vibration phenomena or by corrosion assisted by fatigue. An example of circumferential cracking propogated by fatigue due to vibration induced by high fluid flows across the tubes has been encountered in the Once Through Steam Generators (OTSG) for tubes adjacent to the inspection lane in the vicinity of the fourteenth and fifteenth tube support plates. It has been the practice to stabilize such tubes with pluggable indications by the insertion of a rod inside the affected tube. The rod is attached to the plug which is installed in accordance with conventional practices.
The need to stabilize tubes being plugged as a result of corrosion should consid'er the remaining cross sectional area of the tube and the potential that the corrosion process will continue. Other factors to be considered should be the potential for propogating the corrosion j
defect by fatigue, either as a result of flow induced vibration l
or cyclic loadings due to differential thermal expansion between the plugged tubes and unplugged tubes; whether the defective portion of the tubing is' constrained such that even if it becomes l severed it cannot cause damage to adjacent tubes (e.g., constrained within tubesheet or hardened sludge) and whether local flow velocities are sufficient to cause the severed tube to interact with adjacent tu bes .
DRAFI
11.3 Inservice Inscection Program Requiremen t A revised program for inservice inspection of steam generator tubing shall
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be included in the technical specifications of each pressurized water reactor.
The program shall include the requirements of the latest revision of the Standard Technical Specification (STS) augmented by the changes described
! below:
l The STS have evolved from Regulatory Guide 1.83 " Inservice Inspection of l
Pressurized Water Reactor Steam Generator Tubes," Revision 1. July 1975.
The STS reflect the most recent staff guidance regarding appropriate steam generator tube inspections and accordingly the following discussions of changes will be primarily referenced to the STS. However the changes l
will also be referenced to RG 1.83 as appropriate for completeness of the discussion.
- 1. Tube Inspection The STS and RG 1.83 Part C.2.f currently define a U-tube inspection as meaning an inspection of the steam generator tube from the point of entry (hot leg side) completely around the U-bend to the top support of the cold leg.
l This requirement shall be changed such that U-tube steam generator inspec-tions also include the cold leg between the top support and the tube outl et. Exceptions will be defined in the Supplementary Sampling Require-men ts . This new requirement does not require that the hot leg inspection population and the cold leg inspection population be from the same tubes.
That is, it does not preclude making separate entries from the hot and DRAFT
'.** 1 and cold leg s and selecting different tube i th2 hot and cold i
leg sides to meet the minimum sampling requirements for the inspection.
l l 2. Sample Selection and Testing - -
i (a) The current STS and RG 1.83 part C.4.d allow the regularly scheduled inservice inspections to be limited to one steam generator on a rotating schedule if the results of the previous inspections indicate that all steam generators are performing in a like manner.
RG 1.83 part C.6 mentions and the current STS inservice inspection frequencies require inspections at intervals of from 12 to 24 months which may be extended up to 40 months if two consecutive inspection results indicate that previously observed degradation has not continued and no additional degradation has occurred.
For two, three and four loop plants this could result in an interval of 80,120 and 160 months, respectively, between required inspec-
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t1ons on an individual steam generator.
l This requirement shall be changed to require that each steam generator be inspected at least once every 48 months. -
(b) There are three categories cf inspections mentioned in RG 1.83 part C.5 and specified in the STS. If the results of inspections do not satisfy the criteria for a given category the STS require continuing into the next category until either the category's criteria are satisfied or 1007, of the tubes have been inspected.
This does not recognize situations wherein well defined localized
- groups of tubes (subsets of tubes) experience degradation because of a unique design feature or phenomena. In such cases the licensee could be compelled to. inspect larger numbers of tubes than required to address the speciff
- problem.
I 11
'S I .s Therefore operating plant technical specifications may be amended to provide for the identification and treatment of such subsets of tubes as a special group separata from the general tube inspec-tion population. The subsets would be subject to 100% inspection samplin g. No credit will be taken for the subset inspection in meeting the minimum sample size requirements for the general inspec-tion; nor will the results of the inspection of the subsets be used i
t in classifying the results of the general inspection.
- 3. Supplementary Samplino Requirements RG 1.83 parts C.5 and 7 mention and the current STS specify supplementary sampling requirements based on the number or percentage of inspected tubes found defective or degraded. There are three categories of sampling
( sizes (C-1, C-2 and C-3) progressing from the initial three percent sample to the inspection of 100 percent of the tubes.
This requirement essentially replaces the three current categories with two categories. The first category, the STS category C-1 specifying the initial three percent inspection sample size, remains unchanged. The second category is defined as follows:
If eddy current inspection pursuant to the requirements in Sample Selection and Testing indicates that (a) one or more tubes are defective (have defects with wall penetrations exceeding the plugging limit), or l
(b) 5% or more of the tubes inspected are degraded (have a previously
[
l undetected defect of 20% or greater depth or exhibit greater than 10%
further wall penetration), additional inspection shall be perfomed as i
l follows :
i i
. . .. 'M 1
In each steam generator where the above limits were exceeded, additional tubes shall be inspected. The sample size for this inspection shall be l either 100% of the tubes in the steam generater or shall be based on plant specific analyses defining the . limiting tolerable number of tube failures. Analyses of postulated loss of coolant accident and main steam-line breaks (within and outside containment) with concurrent steam 3 generator tube failures would be performed to determine the tolerable number of tube failures. Some of the specific parameters and assumptions that are considered important in these analyses are the following:
(1) General - In general, the three types of calculations should use, to the extent reasonable, best-estimate performance predictions and assumptions. Operator actions should be assumed where they are reasonable and reflect current operating and emergency procedures.
The computer programs used should be currently accepted transient and accident analysis codes.
(2) Initial Conditions - All calculations should assume nominal plant conditions. In all three analyses described below, power should be assumed to be 100% as opposed to the normally assumed 102% safety analysis initial power assumption. Steam generator and pressurizer water levels and reactor coolant system temperature, pressure, and flow should reflect nominal plant conditions and should be consistent with the other parameters assumed.
l
^ .,
(3) Failed Fuel - In the analyses of the offsite consequences of a steam generator tube rupture (SGTR) and concurrent main steam line break (MSLB) outside containment, the fuel failure estimate should encompass all relevant fuel failure mechanisms, including those iwolving overheating (departure from nucleate . boiling (CNB)) and pellet cladding interaction (PCI). The local power and thermal-hydraulic conditions used in the fuel failure analyses should be based on best-estimate systems analyses.
(4) Initial Coolant Activity - Since most PWR technical specifications allow operation with primary coolant activity at 1.0 pCi/gm for an unlimited time end at up to 60 pCI/gm for a limited time, calcula-tions of the offsite consequences during an SGTR concurrent with MSLB outside containment should be performed assuming the range of initial coolant activity allowed by the technical specification.
To reduce the need for steam generator tube inspection, consideration may be given to reducing the allowable coolant activity consistent with operating experience.
(5) Containment - The analyses of the containment pressurization during an SGTR and concurrent MSLB inside containment should be based on the plant-specific containment and its particular design features and limitations. Other calculations may be referenced if it is shown that they suitably bound the particular plant's containment.
- 13a -
s s s
(6) Atmospheric Dispersion - the value of x/Q used in the analyses of the offsite consequences should consider the range of possible values and associated probabilities of being at those values.
The sample size required to be inspected to ensure that a probability no greater than five percent exists of accepting a generator with greater than the limiting number of defective tubes is then determined by the methods in NUREG/CR-1282.
- This second category of (supplementary) inspection may be limited to a partial length inspection of each tube, providing the inspection includes those portions of the tubes where imperfections were previously found. Furthermore, this supplementary inspection may be limited to subsets of tubes if it can be shown from previous inspection results or from unique structural or mechanical design that the deg adation is limited to well-defined areas of the steam generator tube bundle.
- Notwithstanding any inspection rotation schedule, any additional steam generators not yet inspected during the current inspection shall be inspected in accordance with the requirements in Sample Selection and
( Testing.
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- 4. Inspections for Denting At present there is no specific mention in RG 1.83 and there are no specific requirements in the STS to inspect for denting of tubes.
- 13b -
L .
Therefore a requirement is added such that in the event that tubes will not allow passage of the standard diameter eddy-current testing probe, sufficient gauging or profilometry inspection shall be performed to quantify the magnitude and ex' tent of tube denting. If gauging inspections are perfomed, each inspection shall include gauging or profilometry of all tubes in the steam generator which exhibited denting in a previous insepction. Applicants and licensees shall submit inspection programs for staff review and approval to address denting as part of the plant Technical Specifications. These programs shall include criteria for establishing the scope of the inspections and acceptance criteria (i.e.,
denting limit based upon tube restriction or strain).
- 5. Inspection Intervals The current STS do not require unscheduled inspections in 'the event of a tube leak unless the leak rate exceeds the allowable leak rate limits of the technical specification. This allows plants experiencing tube leakage below the technical specification limit to shutdown, repair the leak and return to service without conducting further inspections.
l This aspect of plant technical specifications shall be changed to require 1
that . unscheduled inspections pursuant to the technical specifications shall l be conducted in the event the plant is. shutdown to repair a primary-to-secondary tube leak regardless of whether or not it exceeds the technical specification leakage rate. Unscheduled eddy-current inspections are not I
required if leakage involves only leaking plugs.
l l 14
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- 6. Acceptance Limits The current STS do not include an acceptance limit for denting.
A definition of the denting 1.imit shall be added to licensee's technical specifications to state that the denting limit means that amount of tube restriction (if gauging inspections are being performed) or strain (if j profilometry inspections are performed) beyond which the tube must be l
l plugged.
l
- 7. Repo rting The current requirement in the STS for the prompt reportine of inservice l
inspection results prior to the resumption of power operation is related to inspection results falling into Category C-3. With the consolidation of the inspection categories discussed earlier it is necessary to redefine the requirement for the reporting of such information.
Therefore licensee's technical specifications shall also be changed to require that if, in the inspection performed pursuant to the Sample Selection and Testing section, 5 percent of more of the inspected tubes are degraded or exhibit greater than 10 percent further wall penetration since the previor s inspection or if any tube has imperfections or denting that exceed the plugging or denting limit the results of the completed l
l inspections shall be reported to the NRC before power operation is resumed.
Bases and Discussion The curren requirements for ISI frequency and scope are based primarily on experience, engineering judgement, and practicality. The required frequency of ISIS was based on the frequency of refueling outages so that regular ISI would not impact plant availability and incur needless expense. The required scope of ISIS was also established primarily on the basis of experience e-w. -
15 -
' ' ' er s ' c-
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and judgement with the goal of achieving safe operation of steam generators
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by selecting a representative tube sample and minimizing personnel exposure associated with ISI. No analysis has previously been performed which included (1) a system and acef dent evaluation to establish the limiting number of defective tubes and (2) st3tistical determination of the required scope of inspection to insure that more than the limiting number of defective tubes will not be undetected.
Although their theoretical basis is limited, the current ISI requirements have been effective in some areas. The required 3% tube inspection sample coupled with the technical specification leak rate limits has been generally successful in identifying tube degradation. This success is due largely to the fact that the primary modes of degradation affecting operating steam generators are mechanistic in nature. They result either from adverse chemical conditions, improper mechanical design, improper materials selection, or a combination of these parameters. The result is that when improper conditions occur, the degradation is not generally isolated but affects a large number of tubes. Thus, the initial 3% sample size is sufficient to identify those steam generators which are experiencing general degradation.
Because of this, the 3% inspection has also proven sufficient to detemine l
if a steam generator tube leak is the result of an isolated incident or if it was the result of a significant mode of general degradation.
Requirement 1 modifies the definition of a tube inspection by requiring that the tubes on the cold leg side from the upper tube support down to the tube outlet also be included in the inspections. The basis for the addition of the cold leg tubes in the inspection is that operating experience has shown that the cold leg side is also susceptible to a variety of degradation machanisms (e.g. , wastage, pitting, denting and fretting induced wear).
16
Requirement 2 requires that each steam generator be inspected no less frequently than once each 48 months instead of the maximum allowable interval of 160 months for a four loop plant inspecting one steam generator per inspection on a rotating. schedule. The basis for this requirement is operating experience which indicates that steam generators at the same unit do not necessarily experience the same degradation mechanisms and that significant degradation can occur much more rapidly than 160 months.
Requirement 2 also provides for the specification of special subsets of tubes. The basis for this provision is to permit tube degradation which is unique to defined localized areas of the steam generator to be excluded from consideration when determining the need to perform supplementary inspec-tions for the overall steam generator. This item makes provision for avoiding excessive inspection of tubes located in areas not experit:ncing degradation. This approach has ciready been incorporated in the technical specifications of some BW units in order to address the fatigue cracking degradation occurring along the open inspection lane in the once through steam generators. This requirement would be implemented by changing the technical specifications to define the degradation phenomena which are unique to the special subsets of the tube population and to define the tubes subject to these phenomena.
Requirement 3 replaces the several supplementary sampling categories mentioned in RG 1.83 parts C.5 and C.7 and specified as Categories C-1. C-E and C-3 in the STS with two categories.
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17 DMFT
,m e
The STS category C-1 currently requires that additional sampling be performed (i.e. , proceed to next category, C-2 or C-3) if (1) any pluggable indications are found during the initial 3 percent inspection or (2) if 5 percent or
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more of the tubes inspected are found degraded. This category remains unchanged.
If no more than 1 percent of t,he tubes inspected are defective and no more than 10 percent of the tubes inspected are degraded the current STS category C-2 supplementary sampling requirements are considerably less than 100%.
The level of sampling required for Category C-2 has not been based on providing any specific statistical confidence level that requires that i the number of uninspected tubes with flaws exceeding the plugging limit will be less than the maximum tolerable number of tubes for postulated
(
. accident conditions.
If more than 1 percent of the inspected tubes are defective or more than 10 percent of the inspected tubes are degraded the current STS category C-3 requires inspection of 100% of the tubes in the subject steam generator and requires extension of the inspection into other steam generator (s). This l category is enveloped within the revised second category.
1 thder the revised second category the required supplementary sample size shall be either 100% of remaining tubes or shall be based on plant specific analyses as discussed in the requirement.
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1 DRJT l
Having determined from the initial 3% sample that a steam generator is experiencing significant degradation, the purpose of the supplementary inspection is to ensure that an intolerable number of defective tubes do not exist in the steam generator considering the design-basis accidents. Although experience indicates that the conditions causing steam generator tube degradation are mechanistic in nature and will generally affect ,a large number of tubes, Thus, the tubes affected can be randomly distributed in the steam generator.
application of either the 100% inspection requirement or the statistical procedures discussed above is appropriate to control the number of defective tubes. In the event that the degradation discovered is not randomly distributed along the length of the tubes or throughout the tube bundle, Requirement 2 allows application of the supplementary inspection requirements to be limited to the specific areas affected when they can be well defined.
With respect to Requirement a which addresses tube denting, operating experience has si.own that surveillance of tube denting is necessary to preclude development of stress corrosion cracking.
Requirement 5 adds the requirement for tube inspections to be perfomed whenever a plant shuts down to repair a leak regardless of whether the leak rate exceeded the technical specification limit. Leak rate limits in the technical specifications are intended to provide assurance that the unit will be shut down for corrective action before tube integrity has become sufficiently degraded to create the potential for tube rupture under normal or postulated accident conditions. The occurrence of leaks during service may be indicative of new phenomena or accelerated rates of degradation and thus the corrective action to be taken upon shutdown shnuld include tube inspections in addition to plugging the leaking tubes.
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Requirement 6, addition of a denting limit definition, is necessary for implementation of Requirement 4 on denting.
The Requirement 7 modification of the reporting requirements is necessary to make the technical specification reporting requirements consistent with the inspection category changes addressed in Requirement 3.
DRAFT l
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s II.4 Improved Eddy Current Techniques .
Requi remen t The following shall be included as part of the test procedure for imervice eddy current testing of PWR steam generator tubing:
- 1. Eddy-current testing techniques or data evaluation techniques which are capable of eliminating tube support plate, tube sheet, denting, or other similar unwanted signal interferences and discriminating among multiple defects shall be used in all steam generator inservice inspections.
- 2. Eddy current probes providing the capability to perform both absolute and differential coil inspections shall be utilized.
Separate probes may be utilized to implement this dual capabi-lity.
- 3. Eddy current data from both the differential and absolute channels shall be evaluated as part of the overall data evaluation program.
l 4. In addition to calibration standards required by Article IV-3200 l
l of Section XI of the ASME Code, an additional standard shall be employed with simulated wear or fretting type flaws to ensure a conservative interpretation of signals for which fretting or wear may represent a possible source of the signals. Typical examples include absolute signals over a significant axial length of the tube, absolute signals for which there has 'been little or no corresponding differential signal, and signals v
which can reasonably be inferred as possible fretting or wear flaws based upon experience (e.g. , indications at the tube to .
baffle plate intersections in the preheater sections of Westinghouse Model D steam generators). The simulated flaws shall be sufficiently tapered and smooth such that they produce little or no differential signal.
Bases Regarding Section 11.4.1, laboratory experiments and field experience have demonstrated the superiority of multiple-frequency ECT and other techniques to eliminate unwanted signal Because interferences and discriminate among multiple defects.
the history of degradation in operating steam generators has resulted in the potential for multiple defects, cracking or tube thinning on top of denting, and other sources of complex signals, these techniques have become essential in accurately evaluating the condition of steam generator tubing. The use of ECT techniques or data evaluation techniques which are capable of i
eliminating tube support plate, tube sheet, denting, or other similar unwanted signal interferences and discriminating among multiple defects should be required in all steam generator ISIS.
As required by Sections II.4.2, 3 and 4, eddy current inspections shall include inspections in the absolute mode in addition to the differential mode to improve defect detection and interpretation capabilities. A wall thinning type flaw which is gradually tapered at its edges, as may be the case for fretting type wear defects, may Such a not produce a detectable signal on the differential channels.
fretting type wear flaw will generally produce a signal on the absolute 22
s e
e channel s . A tapered localized radial fretting or wear standard as opposed to the hole standards specified in the Code may be necessary to correctly interpret the unplitude of the signal .
The tube . hie.h ruptured at Ginna in January 1982 as a result of a long fretting type wear defect had previously been inspected in April 1981 using both the differential and absolute modes.
This tube exhibited no differential signal in April 1981, but did exhibit an absolute signal approximately 5" long, which was not recorded at that time. This April 1981 sigt.al is inter-pretable as less than a 20% indication using the calibration hole standards as specified in the Section XI of the ASME Code.
However, this signal is interpretable as a slightly greater than 40% indication if a fretting or wear calibration standard is used, An ,
which is greater inan the 40% plugging limit for Ginna.
evaluation of the absolute signal in April 1981 using a fretting or wear standard may have resulted in the tube being plugged before the wear had proceeded sufficiently through wall to cause the l
rupture.
l 23 c, . = '
- -t i ' i t , ;
h ibh'kh'
l II.5 Primary to Secondary Leakane Limit Requirement Each licensee shall revise their technical specifications for primary to secondary leakage rate limits to be consistent with the latest revision of the applicable Standard Technical Specifications.
l Bases ;
Regulatory Guide 1.83 and the Standard Technical Specifications require an :
1 unscheduled steam generator inservice inspection when the technical specification leakage rate limit is exceeded.
The Standard Technical Soecifications (STS) limits primary to secondary leakage through all steam generators not isolated from the reactor coolant system as well as through any one steam generator not isolated from the reactor coolant system. These limits are based on two considerations.
First, the total steam generator tube leakage limit of 1 gpm for all stea1 generators ensures that the dosage contribution from tube leakage will be limited to a small fraction of 10 CFR Part 100 limits in the event of either a steam generator tube rupture or steam line break.
This limit is consistent with the assumptions used in the analysis of these accidents. Second, the 500 gpd (0.34 gpm) leakage limit per steam generator ensures that steam generator tube integrity is maintained in the event of an MSLB or under LOCA conditions.
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In a practical sense the leakage rate limits provide a very important indication .
of the existence or rate of steam generator tube degradation. Experience has shown that some forms of degradation can develop in a period of time shorter than the routine inspection intervals or may be difficult to detect with current ECT techniques. In the event that such degradation occurs, the leakage rate limits act to indicate when plant shutdown, ISI, and corrective actions should be taken. From a practical standpoint, this is perhaps the most important function of the leakage rate limits.
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H.7 Secondary Water Chemistry Program Reoufrement Licensees shall incorporate a requirement .for a secondary water chemistry program to m1nimize steam generator tube degradation. The requirement for the program shall be specified in a condition to the license which will stipulate that the program itself shall be defined in specific plant procedures. The staff will review the plant specific secondary water chenistry program for compliance with the following criteria. The specific plant program should address measures taken to minimize steam generator corrosion, including; materials selection, chemistry limits and control methods. In addition, the specific plant procedures should include progressively more stringent corrective actions for out of specification water chemistry conditions. These corrective actions must include power reductions and shutdowns, as appropriate, when excessively corrosive conditions exist. Specific functional individuals must be identified as having the responsibility / authority to interpret plant water chemistry information and initiate appropriate plant actions to adjust chemistry, as necessary.
Although the requirement for a program which includes the above named elements shall be included in the license, the specific plant procedures implementing the program will not be specifically included in the license.
To provide review criteria for determining whether plant specific secondary l water chemistry is acceptable, the staff is currently revising the secondary water chemistry guidelines which are in SRP 5.4.2.1. The revision to these guidelines will incorporate the September 1981 "PWR Secondary Water Chemistry Guidelines" as a review basis. These guidelines were prepared by the steam
generator owners group water chemistry guidelines committee and represent an industry consensus opinion for state-of-the-art secondary water chemistry con trol . .
Bases The corrosion of steam generator materials may result in primary to secondary leakage if preventative measures or repairs are not undertaken on time.
Such leakage may allow the release of radioactivity to the environment. The necessary repairs and preventative measures have resulted in significant occupational radiation exposures. The accomplishment of improved secondary water chemistry has been recognized by the industry in general and by the staff as an important factor in reducing steam generator materials corrosion.
Therefore, to provide assurance that all PWR licensees will uniformly and consistently implement proper monitoring and control of secondary water chemistry, thus reducing the need for repair and preventative activities 1
resulting in occupational radiation exposures and reducing the potential for I
radioactive releases to the environment, the requirement for such a program shall be included in the license.
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11.8 Condenser Inservice Inspection Program -
A license condition similar in nature to that required' by Section II.7 of condenser this report shall be added to include a commitment to perform inservice inspection if the secondary water chemistry conditions and limits used tu establish power reduction requirements are exceeded to the extent that a power reduction is required twice per quarter as a consequence of condenser leakage. The condenser inservice inspection program shall be included in the plant operating procedures.
Bases Condenser operating experience was sumarized in EPRI-NP-481, " Steam Plant Surface Condenser Leakage Study," by the Bechtel Corporation.
The survey assessed the leakage integrity of the condenser and the reliability and operability of the downstream components to the f Air and water contamination introduced from the recirculation water.
inleakage through the failed condenser tubing can contaminate the condensate, feedwater, steam generator water, and steam, which, in turn, degrades the structuial integrity of the steam generator tubes, The tolerance turbine and other components in the cooling system.
l to a given leak in a given plant is a function of the impurity content of the recirculation water, the presence or absence of condensate demineralizers, the materials in the condenser and feedwater trains, and the specification requirements for the reactor coolant cycle water.
Many undersirable contaminants enter the secondary system through condenser leaks and condenser integrity is essential to maintaining good water chemistry.
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o Condenser tubes in the impingement, condensing, and air-removal sectors of the condenser are subject to different failure rates and failure mechanisms. To some extent, failures resulting from vibration are related to service operating conditions. Tubes in the impinge ent sector are susceptible to erosion by steam and to severance by missiles.
Likewise, when ammonia-sensitive alloy tubes are located adjacent to the air-removal sector of the condenser, a high incidence of amonia-induced failures can be anticipated with AVT coolant water control .
Localized concentrations of ammonia can be orders of magnitude greater in the vapor phase than in the bulk condensate. A high concentration of ammonia in the condensate may induce failure of copper alloys by stress-corrosion cracking.
l Air inleakage into the condenser can cause corrosion of copper-containing condenser' tubes and feedwater heater materials. When ammonia is also present, stress-corrosion cracking of copper-base alloys, such as aluminum brasses or Admiralty bronzes can also occur. The copper-nickel alloys are more resistant to ammonia cracking, but can still be a source of copper ions . As noted above, copper ions entering the feed-water from these sources can trigger denting reactions in the steam j
j generators . Steps are being taken by the utilities to eliminate the use of ammonia-sensitive alloys from the air-removal section of the condensers and replace them with more amonia-resistant alloy tubing.
Where denting is a concern, steps are being taken to. eliminate all copper alloys from the condensers, by using such materials as stainless steels (for fresh-water service), Allegheny-Ludlum 6X, or titanium.
Clearly, maintenance of a tight condenser will eliminate the primary 2e DRAFT
s source of the oxygan and chloride ions in the system and help to centrol
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denting in the steam generators. -
It is intended that the new limits for secondary water chemistry discussed in Section II.7 will provida the incentive to maintain proper condenser integrity. The condenser inspections required in this sectior; are a backup measure to assure condenser integrity only if there are repeated indications that satisfactory secondary water chemistry can not be maintained.
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12.9 Upper fnspection Ports Requirement For PWRs with U-tube steam generators that are licensed after January 1, 1983, upper inspection ports shall be installed before an operating license is issued. The ports shall be loc"ated so that visual inspection of upper support plates and inner row U-bend tubes can be perfomed.
Upper inspection ports will not be required to be installed in operating ,
plants by this generic requirement. The need for inspection ports in operating plants will be based on plant operating experience on a case-by-case basis.
Bases Steam generators are generally equipped with only lower inspection ports.
Operating plants including North Anna 1 and 2 Farley 2, Salem 2 and Trojan have or will install ports in the vicinity of the upper tube support plate. The primary reasons for installing these ports have been to evaluate and monitor the effects of denting in the upper portion of the steam generator and to remove tube specimens for examination. Itwever, specimens removed have included tubes degraded not only by denting, but also by other modes of degradation. Prior to the occurrence of extensive hourglassing of the tube support plate flow slots, limited inspection of the upper portion of the steam generator can be conducted by photographing through the flow slots from the lower ports. This technique allows for only limited inspection and ports located at the higher elevation provide a much more effective means of inspection. Furthemore, denting usually affects the lower support plates first and when the flow slots in the lower plates close up, which has happened in several operating units, the upper portion of the steam generator secondary side is inaccessible for inspection.
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-s s installation of inspection ports in operating steam generators can result in extended outages and additional exposure of personnel to radiation. There fore ,
for those plants not yet in operation it is advantageous to install inspection ports prior to initial critic'ality. Several recently licensed plants have requirements, based on reviews specific to those plants, to install ports early i
in the life of the plant. Based on consideration of the impact of installing upper inspection ports in operating plants the staff plans to require installation in additional operating plants only as a result of case-by-case reviews of plant specific operating experience.
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s III. PLANT SYSTEMS RESPONSE ,
III.1 NEW REQUIREMENTS 111.1.1 Reactor Coolant System Pressure Control Du' ring a SGTR Requirement Licensees / vendors should determine the optimal means of controlling and reducing reactor coolant system pressure during and following a steam generator tube rupture with emphasis on the most effective use of existing equipment. Licensees should optimize pressure control procedures, techniques and systems considering a SGTR with or with-out offsite power. The use of the PORY (including throttling capability) and repeated cyclic operation), nomal spray and auxiliary spray systems should be studied and, where appropriate, factored into the SGTR emergency procedures. The study should address the following objectives:
- 1. Minimizing the primary to secondary leakage through the broken steam generator tube;
- 2. Maximizina control over system pressure;
- 3. Minimizing the chances of producing voids in the RCS, and other comlicating effects.
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Bases Without forced reactor coolant flow, which may occur due to RCP trip or as a result of a loss of offsite oower, the necessary RCS depressurization following a SGTR is more difficult because of the loss of nomal pressurizer spray.
RCS fluid contraction caused by the cooldown from the dumping of steam to either the condenser or to the atmosphere, will result in some reduction in RCS pressure but other measures must be taken to expeditiously reduce the RCS pressure to the point where flow into the damaged steam generator stoos. The pressurizer PORV was used during the Ginna and Prairie Island SGTR events to reduce RCS oressure. However, control of pressure is difficult with the PORV since its use creates an additional loss of coolant. The decrease in pressure can be so raoid that steam voids may be formed in the uoper vessel head, and in the top of the U-tubes and further comolicate the deoressurization. Void formation can lead to concerns regarding core, cooling. The Ginna operators were sufficiently concerned that they left the safety injection pumps operating thereby overfilling the steam generator with the ruptured tube and challenging the safety valve.
It is not apparent that the auxiliary spray from the c'harging system could have successfully lowered RCS pressure to the point where flow out the hmken tube is stopped. It may have been that, by spraying cold charging fluid into the pressurizer, the decrease in pressure would have resulted in void femation, thus expanding RCS fluid and filling the pressurizer, and rendering further spray flow ineffective. This phenomena should be examined as well as the thermal stresses on the spray nozzle itself.
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1 221.1.3 Engineered Safety Features (ESF) Issues 111.1.3.1 Safety Injection Signal Reset Requirement Control logic associated with safety-related equipnent should be reviewed by licensees to minimize the loss of safety function as-sociated with SI Reset. For example, automatic actions such as the switchover of safety injection (SI) suction from the boric
, acid storage tanks ,(BAST) to the refueling water storage tanks I
(RWST) should be evaluated with respect to whether the switchover should be made on the basis of low BAST level, without consideration of the condition of the SI signal.
Bases In the Ginna design, emptying of the BAST, following reset of the SI signal, can cause loss of all SI pumps due to cavitation if rapid manual actions are not taken. This is due to the design wherein SI pump suction shifts automatically on low BAST level from the BAST to the RWST only if the SI signal has not been reset.
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An improved design may be achi.eved if automatic transfer from the BAST to the RWST is provided on low BAST level under all operating condi.tions. This is a desirable feature since the event of a tube rupture the contents of the BAST may not be reduced to the low ,
level switchover setpoint for 20 to 30 minutes during which time the operators are precluded by procedures from resetting SI . SI must be reset before CI (containment isolation) can be reset. Resetting CI allows operation of equipment and systems that can aid in mitigating the consequences of a steam generator tube rupture.
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III .l .3. 2 Containment Isolation and Reset Requirement All licensees should review and evaluate the response of the let-down system to contairnent isolation and reset signals. Specifi-cally, licensees should evaluate the containment isolations systems l to assure isolation of the low pressure portion of the letdown I
l system inside containment (and its relief valve), thereby avoiding an unnecessary RCS leak during the event.
Bases During the Ginna event the RCS letdown containment-isolation valve closed, as designed, on a containment isolation signal.
However, as pressurizer level recovered later in the event the selected letdown or'fice isolation valve and the level control
- valve reopened as designed. Consequently, the letdown line was connunicating with the reactor coolant system while the downstream portion of the letdown line remained isolated and the relief valve on the letdown line opened at a setpoint pressure of 600 psig.
This valve relieves to the pressure relief tank and was the major contributor to the pressure relief tank level. The Ginna contain-ment isolation design therefore caused an unnecessary and undesirable leak during an already complex event.
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V.l.4 Standard Technical Specification Limit for Coolant Indine Activity Requi remen t All PWRs that have technical s'pecifications for coolant activity l
limits whici, differ from the STS in iodine limits or surveillance requi rements, should incorporate the Standard Technical Specifi-l cation requirements.
l f Bases As stated in NUREG-0916, during the Ginna SGTR event the amount of primary to secondary leakage and the total amount of water and steam released to the environment were larger than would normally be predicted because of valve malfunctions and operator actions. The staff'found that the potential exists for doses to exceed part 100 guidelines from a design basis SGTR accident and that these doses would occur only if there were an unlikely, but not impossible, set of circumstances, namely; primary coolant with iodine concentration at the Standard Technical Specifica-tion coolant iodine concentration spiking limit of limit of. 60 uCi/g dose-equivalent I-131 maximum flow rate through a double-ended tube rupture, flow through the tube rupture prolonged for two or more hours, filling of the steam generator and steam line of the affected steam generator, releases through the affected steam generator's safety or atmospheric dump / relief valves as a two-phase mixture, and conservative atnopsheric dispersion factors. The actual radiological consequences of the Ginna accident were not severe because the reactor coolart iodine concentration was very low, 0.057 u Ci/g dose-equivalent I-131 (about 2% of the plants T.S. limit), and because the meteorologic conditions were far more favorab'e, with respect to offsite doses, than the conservative assumptions used in the prior analyses.
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Wwever, eleven PWR's do not have any specific limits on radiofodine, but do have limits on total ga: ma a'ctivity.. While the' total primary coolant activity might remain substantially below the total activity technical specification s,hutdown value, the actual radiofodine levels could be very high. Furthermore, iodine spiking must be accomodated, but controlled, and surveillance to assure compliance is necessary.
Since the Standard Technical Specifications incorporate dose equivalent iodine concentration limits for all th PWR vendors which (1) incor-porate suitably conservative limits. (2) accomodate but control spiking of iodine, and (3) incorporate adequate surveillance for both f primary and secondary coolants, the staff requests that they be adopted for all PWRs.
UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:
James P. Gleason, Chairman Dr. Oscar H. Paris Frederick J. Shon
_________________________________x CONSOLIDATED EDISON COMPANY OF : Docke t Nos. 50-247-SP NEW YORK, INC. (Indian Point, .
50-286-SP Unit No. 2) :
l POWER AUTHORITY OF THE STATE OF :
NEW YORK, (Indian Point, January 12, 1983 Unit No. 3) :
x CERTIFICATE OF SERVICE I certify that I have served copies of CON EDISON 'S TESTIMONY OF. SAMUEL ROTHSTEIN CONCERNING BOARD QUESTION 2.2.1. by deposit in the United States mail, postage prepaid, this 12th day of January, 1983.
Docxeting and Service Branch Dr. Oscar H. Paris Office of the Secretary Administrative Judge U.S. Nuclear Regulatory Atomic Safety and Licensing Cc= mission Board Wasnington, D. C. 20555 U.S. Nuclear Reculatory
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James P. Gleason, Esq., Chairman Commission Washington, D. C. 20555 Administrative Judce
. 513 Gilmoure Drive ~ Mr. Frederick J. Shon Silver Springs, Maryland 20901 Administrative Judge Atomic Safety and Licensing Board U.S. Nuclear Regulatorv Commission Wasnington, D.C. 20555
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Joan Miles Alan Latman, Esq.
Indian Point Coordinator 44 Sunset Drive New York City Audubon Society Croton-on-Hudson, New York 1052C 71 W. 23rd Street, Suite 1828 New York, New York 10010 Richard M. Hart: man, Esq.
Lorna Salzman Greater New York Council on Friends of the Earth, Inc.
Energy 208 West 13th Street c/o Dean R. Corren, Director New York, New York 10011 New York University -
26 Stuyvesant Street Zipporah S. Fleisher New York, New York 10003 West Branch Conservation Association Atomic Safety and Licensing 443 Buena Vista Road Board Panel New City, New York 10956 U.S. Nuclear Regulatory Commission Mayor F. Webster Pierce Washington, C. C. 20555 Village of Buchanan 236 Tate Avenue Atomic Safety and Licensing Buchanan, New York 10511 Appeal Board Panel U.S. Nuclear Regulatory Judith Kessler, Coordinator Commission -Rockland Citizens for Safe Washington, D. C. 20555 Energy ~
300 New Hempstead Road Richard L. Brodsky New City, New York 10956 Member of the County Legislature -
Westchester County David H. Pikus, Esq.
County Office Building Richard F. Czaja, Esq.
White Plains, New York 10601 330 Madison Avenue New York, New York 10017 Phyllis Rodrigue=, Spokesperson Parents Concerned About Amanda Potterfield, Esq.
Indian Point Johnston & George P.O. Box 125 528 Iowa Avenue Croton-on-Hudson, New York 10520 Iowa City, Iowa 52240 Charles A. Scheiner, Co-Chairperson Ruthanne G. Miller, Esq.
Westchester People 's Action Atomic Safety and Licensing Coalition, Inc. Board Panel P.O. Box 488 U.S. Nuclear Regulatory White Plains, New York 10602 Commission Washington, D. C. 20555 Stewart M. Glass Regional Counsel,.Roca 1347 Federal Emergency Management Agency 26 Federal Plaza New York, New York 10278
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Janice Moore, Esq. Charles,J. Maikish, Esq.
Office of the Executive Litigation Division Legal Director The Port Authority of U.S. Nuclear Regulatory New York and New Jersey Commission One World Trade Center Washington, D. C. 20555 New York, New York 10048 Paul F. Colarulli, Esq. Ezra I. Bialik, Esq.
Joseph J. Levin, Jr., Esq.
Steve Leipsis, Esq.
Pamela S. Horowitz, Esq. New York State Attorney Charles Morgan, Jr., Esq.
General's Office Morgan Associates, Chartered 1899 L Street, N.W. Two World Trade Center New York, New York 10047 Washington, D. C. 20036 Alfred B. Del Bello Charles M. Pratt, Esq. Westchester County Executive Stephen L. Baum Power Authority of the State 148 Martine Avenue White Plains, New York 10601 of New York 10 Columbus Circle Andrew S. Roi fe , Esq.
New York, New York 10019 New York State Assembly Albany, New York 12248 Ellyn R. Weiss, Esq.
William S. Jordan, III, Esq. ,Renee Schwartz, Esq.
_ Harmon & Weiss Paul Chessin, Esq.
1725 I Street, N.W., Suite 506 Washington, D. C. Laurens R. Schwartz, Esq.
20006 Botein, Hays, Sklar & Her berg
, Joan Holt, Project Director 200 Park Avenue New York, New York 10166 Indian Point Project New York Public Interest Stanley B. Klimberg Research Group New York State Energy Office 9 Murray Street New York, New York 10007 2 Rockefeller State Plaza Albany, New Zark 12223 Melvin Goldberg Ruth Messinger Staff Attorney New York Public Interest Memoer of the Council of the City of New York Research Group District #4 9 Murray Street City Hall New York, New York 10007 New York, New Yorn 10007 Jeffrey M. Blum Marc L. Partis, Esq.
New York University Law School County Attorney 423 Vanderbilt Hall County of Rockland Washington Square South 11 New Hempstead Road New York, New York 10012 New City, New York 10Q10
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Donald Davidoff, Director Craig Kaplan, Esq.
Radiological Preparedness National Emergency Civil -
Group Liberties Committee Empire State Plaza 175 Fifth Avenue-Suite 712 Tower Building - Room 1750 New York, New York 10010 Albany, New York 12237 David B. Duboff Jonathan D. Feinberg Westchester Peoples' New York State Public Action Coalition '
Service Commission 255 Grove Street '
Three Empire State Plaza White Plains, N. Y. 10601 Albany, New York 12223 Steven C. Sholly Spence W. Perry Union of Concerned Office of General Counsel Scientists Federal Emergency 1346 Connecticut Ave., N.W. Management Agency .
Suite 1101 500 C Street, Southwest Washington, D.C. 20036 Washington, D.C. 20472 Dated: January 12, 1983 '
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