IR 05000348/1987021

Insp Repts 50-348/87-21 & 50-364/87-21 on 870817-21.No Violations or Deviations Noted.Major Areas Inspected:Plant Chemistry & IE Notices Re Erosion/Corrosion

ML20238F475
Person / Time
Site:	Farley
Issue date:	09/02/1987
From:	Kahle J, Ross W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20238F469	List: IR 05000348/1987021 ML20238F468
References
50-348-87-21, 50-364-87-21, IEB-81-03, IEB-81-3, IEIN-86-106, IEIN-86-108, IEIN-87-036, IEIN-87-36, NUDOCS 8709160180
Download: ML20238F475 (14)

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UNITED STATES m CEcog'o

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1. NUCLEAR REGULATORY COMNISSION

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[P _ REGION ll

,- g 101 MARIETTA STREET, *

Ij r: ATLANT A, GEORGI A 30323

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Report Nos.: 50-348/87-21 and 50-364/87-21 Licensee: . Alabama Power Company

.600 North 18th Street Birmingham, AL 35291-0400 Docket Not : 50-348 and 50-364 License Nos.: NPF-2 and NPF-8

, Facility Name: Farley 1 and 2 Inspection Conducted: August 17-21,-1987 Inspector: I b Y. J. Ross / Date Signed Accompanying Pe nnel J. 8. Kahle l Approved by:

~ B. Kahle, Sectidn Chief Thh Date Signed

. Division of Radiation Safety and Safeguards SUMMARY Scope: This routine, announced inspection was conducted in the area of. plant chemistry and IE Notices related to erosion / corrosio Results: No violations or deviations were identifie l l

8709160180 870910 DR ADDCK 050 8 l

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' Persons Contacted Licensec Employees  !

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• J. D. Woodard, General Plant Manager (GPM) 1

• D. W. Morey, Assistant GPM-Operations

• C, D. Nesbitt, Technical Manager

• R. G. Berryhill, Systems Performance and Planning Manager R. Bayne, Chemistry and Environmental Supervisor

• M. C. Coleman, Systems Performance Supervisor J H. Erbskorn, Sector Supervisor, Mechanical Maintenance )

D. B. Hartline, Systems Performance Engineering Supervisor 1 D. Klasing, Assistant Performance Engineer 1 T. Livingston, Unit 1, Chemistry Foreman

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M.- E. Perry, Quality Control Specialist / Chemistry J. Porlier, Chemistry and Environmental Engineer R. Robinson, Unit 2 Chemistry Foremon

• R. T. Wood, Plant Chemist Other licensee employees contacted included chemistry technician Nuclear Regulatory Commission

• H. Bradford, Senior Resident Inspector

• H. Miller, Resident Inspector

• Attended exit interview Exit Interview  !

The inspection scope and findings were summarized on August 21, 1937, with ]

those persons indicated in Paragraph 1 above. The inspector described the q areas inspected and discussed the inspection findings. No dissenting i comments were received from the licensee. The licensee did not identify as proprietary any of the material provided to or reviewed by the ,

inspector during this inspectio l 1 Licensee Action on Previous Enforcement Matters ]

This subject was not addressed in the inspectio Plant Chemistry (79701) j I

This inspection was the fourth in a series of assessments of the j licensee's capability to maintain the integrity of the primary coolant I pressure boundary, specifically the integrity of the steam generator l tubes. As noted in the last inspection report (see Inspection Report J 86-01 dated February 12,1986), the principal concern vas the continuing i buildup of copper-iron oxide sludge in the steam generators of both units, d even though secondary water chemistry was being controlled in a manner )

prescribed by the vendor and the Steam Generators Owners Group (SGOG). In

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I the.19-month period since the last inspection both Farley units had undergone refueling outages during which. the integrity of the steam generator tubes was again tested using eddy-current probes, and each steam generator was lanced to remove oxide sludge. Continued accumulation of large amounts of sludge was found in the Unit 1 steam generators (1,111 pounds, 854 pounds, and 683 pounds in Steam Generators "A," "B,"

and "C") and lesser amounts (382, 391, and 396 pounds) in steam generators

"A," "B," and "C" of Unit 2. Of equal concern, however, was the identification of primary side cracking in the tube sheet regions and secondary side cracking at tube support plate elevations of the three Unit 2 steam generators. Consequently, 30 tubes in "2A," 19 in "2B," and 44 in "2C" were plugged to prevent possible tube leak Through an audit of chemistry data and discussions with cognizant personnel on the plant staff the inspector established that the licensee was addressing deterioration of steam generator tubes and wastage of carbon steel components of the steam and power system (i.e., the secondary water system) in a number of ways. These actions are summarized below and have been evaluated as to their potential for mitigating existing primary and secondary side stress-induced cracking as well as enhancing long-term protection against other types of corrosion related deterioratio Plant Design and Operation The inspector' reviewed the secondary water system of each unit as to the effectiveness of the principal components in preventing ingress / transport of contaminants that cause corrosion of steam a generator tube (1) Main Condenser Through an audit of chemistry data acquired since the last inspection in this area (January 1986) the inspector observed that the quality of water in the condenser hotwells had been maintained at high levels in both units; e.g., cation conductivity of 0.16 0.02 umho/cm and less than 5 ppb dissolved oxygen. The measured values for cation conductivity were considered to be biased on the high side by the presence of boric acid that had volatilized from the steam generators. Air inleakage had been maintained at less than 5 SCFM most of this period, although slightly higher leak rates (6 to 8 SCFM) were being measured during this inspection. Although the Unit I condenser had experienced one tube leak, caused by steam impingement, the licensee attributes the leak-tightness of the condensers to the following factors: use of condenser tubes fabricated from titanium; inspection of condensers for sludge and weak or loose parts during each refueling outage; initiation of a leak detection program when air inleakage exceeds 5 SCFM; and use of chlorination and an Amertap tube cleaning system to prevent tube damage caused by microbiological organisms (e.g.,

asiatic clams or corbicula).

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The inspector concluded that the licensee was continuing to prevent the main condenser from being a pathway for ingress of potential corrosive species into the secondary water syste (2) Service Water System f

The inspector was informed that pipes in this system were being degraded through fouling by macrorganisms and also undergoing

- attack by microbiological induced corrosion (MIC)). The fouling

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problem has been described in LER 86-014-00 dated September 2, 1986, and in Inspection Report No. 50-348, 361/86-18. The bacteria that were causing MIC had been identified and were being controlled in the same manner as corbicula; i.e., by injection of chlorine dioxide into water pumped from the plant's storage pon However, the licensee was planning to take additional steps to prevent MIC; e.g., (1) develop a biocide program more specific and effective than the use of chlorine dioxide; (2) add a dispersant to reduce sedimentation in the pipes; (3) paint the inner surfaces of small diameter pipe to reduce pitting and galvanic reactions and to assist in the dispersal of solids; and (4) replace degraded carbon steel pipe with stainless steel pipe, The licensee was addressing the issue of flow blockage of service water lines in response to IE Bulletin 81-03 and Inspector Followup Item 86-18-0 However, the inspector concluded that until appropriate water treatment programs have been developed for both macro- and micro-organisms the licensee should consider MIC as a special type of biological fouling and cause of pipe failure and, therefore, surveillance of raw water systems, especially in dead legs or other stagnant lines, should be increase (3) Water Treatment Plant Through a review of process data and discussions with cognizant chemistry personnel the inspector established that high quality water was continuing to be produced by the water treatment plant for use in both the primary and secondary coolant system of the Farley plant; e.g., specific conductivity of 0.07 umho/cm, dissolved oxygen less than 5 ppb, silica less than 5 ppb, mineral ions (sodium, calcium, magnesium, fluoride, chloride, sulfate) less than or equal to 1 pp The requirement for condensate makeup had increased during the fifth fuel cycle for Unit 2 because steam generator blowdown in this unit was no longer being recycled but, instead, was again being discarded as waste water. An audit of analyses of water in the Condensate Storage Tank revealed that, since February 1986, the cation conductivity of this water had been 0.16 0.02 umho/cm and the concentration of dissolved oxygen had usually been 40 10 pp The inspector censidered the purity of the water treatment plant

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H product and' the water in the ' CST to be well within the criteria L recommended - by . the SG0G and to indicate that ingress - of .

L potential corrodants through this pathway had been effectively'

prevented. Likewise the. concentration of organic material in l the influent to the water treatment plant (i.e., river water via L the storage pond) was being reduced from approximately 3 ppm to 40 ppb, a concentration range .that was not considered to be detrimental' for makeup wate (4) Feedwater Heaters

, During the refueling outage for Unit 2 in April-May 1986' the

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remainder of the original feedwater heaters in this . Unit (1A, IB, 2A, 2B, 5A and SB) were replaced. This action completed the licensee's program of replacing all components in the secondary system that were aluminum-bronze fabricated condenser tubefrom cop)per sheets alloys (except

. By installing the feedwater heaters with-stainless steel tubes the licensee was attempting to reduce, and eventually terminate, transport of copper corrosion products to the steam generators and, thereby, reduce the' potential for steam generator tube denting. Consequently, the inspector considered this tube replacement program to be a very positive action relative to maintaining the integrity of the primary coolant pressure boundar Based.on previous experience with Unit 1, the licensee was aware

. that transport of copper corrosion products would not be immediately terminate Although all copper-containing components .in Unit I had been changed out prior to the seventh fuel cycle, an analysis of the sludge removed from the steam generators at the end of this cycle showed that approximately 50 percent ' (approximately 500 pounds per steam generator) was copper while only 30 percent (approximately 300 pounds) was iron. During startup for the next Unit 1 fuel cycle (Cycle 8)

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in December 1986 the licensee performed a study of corrosion product transport in an effort to identify the sources of both soluble and insoluble iron and copper. The results of this study confirmed that both iron and copper, principally in a filterable form, was being transported by the condensate and heater drains; 1.e., from the low pressure and high pressure components of the secondary coolant system - including the main

condenser.

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The study also verified that the transport rate of both iron and copper was several times greater during startup than when a unit was at stable operation at full powe One of the conclusions drawn from this study was that "the copper transport undoubtedly will gradually decrease with time as most transport appears to be resulting from deposits formed when the [feedwater] heaters were tubed with copper alloys."

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i The inspector concluded that the licensee recognized that the transport of copper to the steam generators continues to form an environment that is conducive to tube dentin (5) Condition of Steam Generators During this inspection the inspcctor observed that the licensee was planning to accomplish several activities during the fifth refueling outage in October 1987, to enhance the integrity cf the Unit 2 steam generators. These activities were designed to terminate tube cracking that had been attributed to long-term build up of magnetite in tube support plate openings (i.e.,

secondary side denting and stress corrosion cracking) as well as cracking caused by primary side stress corrosion within the tube sheet region. Similar degradation had not been observed in Unit 1 although magnetite buildup had been observed in the tube to tube support plate openings since the fourth refueling outage in 198 (a) Magnetite buildup and denting During the initial inspection of plant chemistry of the Farley plant in March 1984 the inspector had noted that although conditions for tube denting and stress corrosion cracking were present in all steam generators (e.g., large amounts of copper and copper oxide in the sludge and chloride in the steam generator water) no steam generator tubes in either unit had been plugged because of leakage or excessive degradatio However, in September 1984, during the third refueling cycle for Unit 2, three tubes had to be plugged due to extensive wall thinning and one leaking tub The licensee also initiated boric acid soaking during the next refueling outage for this unit and subsequently in the fifth cycle in 1986 began the same program for continuous boric at.id feed to the steam generator that had been initiated ' Unit 1 during the fifth fuel cycle of 198 Although the boric acid soaks and additions appear to have been successful in preventing denting in Unit 1 the inspector was informed, during the current inspection, that tube cracks had been found at nearly all tube support plate elevations in Unit 2 by eddy current measurements taken during the refueling outage in April-May 198 In an effort to eliminate the cause of secondary side i cracking, i.e. , buildup of magnetite in the tube-tube support plate openings, the licensee was planning to use a

" pressure pulse" procedure in an effort to dislodge the magnetite from the openings. This activity will be

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performed during the Unit 2 refueling outage in October 198 The pressure-pulse method had been developed by Westinghouse and appeared to .be .similar to methods performed on once-through-steam generators in the pas The licensee agreed to provide the Farley Senior Resident Inspector with a copy of the vendor's safety evaluation for the use of this method prior to cleaning the Unit 2 steam generator '(b) Primary Side Cracking The -discovery of stress induced cracking- on the primary coolant side of steam generator' tubes has been a recent phenomenon in certain models of Westinghouse steam-generator Because of the. location of crack initiation, as well as the parameters of crack growth, this. type of tube failure is attributed to stress. induced on the inner surface of the tube'and assisted by the aqueous environment over a long incubation period. The licensee had previously addressed the possibility of stress levels in the upper (U-bend) portion of Row 1 tubes by preventively plugging all of Row 1 tubes in both units. However, the initiation of stress induced cracks in the tube sheet region aad nut been anticipated. The inspector was informed that the presence .of this type of cracking in Unit 2 only- may be attributable to the different procedures used to establish bonding of the tubes and tube sheets during fabrication of the steam generators. The tubes in Unit I were bonded by explosive means while the Unit 2 tubes were mechanically hard rolled against the tube sheet surfac The inspector observed that the licensee had initiated three actions designed to minimize the number of tubes that will have to be plugged because of primary side crackin The integrity and strength of a cracked tube had been redefined on the basis of the length of unflawed tubing, above the highest crack that remains fully bound to the tube sheet.- A proposed change in the Farley Technical Specifications would give credit to this "F-star" length of flawless tube for prevention of tube ejection or other types of tube f ailure caused by primary side crack within the tube sheet region. This credit would apply to the Technical Specification requirements for surveillance and plugging of degraded tubes. Secondly, the licensee was planning to shot-peen the sections of tubes within the tube sheets in an effort to transfer stress levels from the primary (ID) side to the surface (OD) adjacent to the tube sheet and, thus, induce compressive forces on existing cracks that would retard growth. Finally, plans were being

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made to insert sleeves within the flawed tubes throughout the height of the tube sheet to restore the integrity of the flawed segments of tube Based on present technology, all of the above corrective actions appear to offer acceptable means of maintaining the integrity of the steam generator tubes, and, thereby, the primary coolant pressure boundar (c) Sludge Removal and Hideout Return Blowdown The inspector reviewed actions taken by the licensee to remove both insoluble and soluble contaminants from the steam generators of both units since the last in:pection in this area. As discussed earlier, during the fourth refueling outage for Unit 2 in April-May 1986 all three steam generators were sludge lanced and the following weights of sludge were removed: 382 pounds from "2A."

391 pounds from "28," and 396 pounds from "2C." The composition (by weight) of the sludge from "2A" was 2 30 percent iron, 50 percent copper, 3 percent zinc, and 2 percent nickel. Likewise, the three steam generators in Unit I were sludge lanced during the seventh refueling outage during October-November 1986 and the following weights of sludge were removed: 1,111 pounds from "1A,"

854 pounds from "18," and 683 pounds from "1C." The composition of the sludge was essentially the same as found in Unit Although the efficiency of sludge lancing varies, the results of the sludge removal from both units during the last three refueling outages indicated that the amount of sludge in the steam generators was decreasing during the last four years but still not as rapidly as observed at other PWRs in Region II since the SG0G guidelines have been implemente The inspector also reviewed the extensive hideout return data that had continued to be collected by the licensee, especially during the 24-hour hold periods during plant startup and cooldow During these periods of maximum solubility (i.e., approximately 350 F) the blowdown rate is maximized to remove soluble contaminants; e.g., sodium, silica, chloride, fluoride, and sulfat Although these periods afford the licensee the best opportunity to eliminate potential corrodants, hideout return removal is dependent on the mass of metal oxide sludge that covers the tube sheet and within crevices of steam generators where ions " hide out" and form corrosive environments. Even though the steam generators had been fed with water of very high purity and the steam generators had been blown down

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. during each startup after refueling outages (after. being sludge lanced) considerable concentrations of mineral-ions continued to be found whenever hideout return-blowdown was performed.during the last year.

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removing hideout return to be the most comprehensive that he was aware of. However, the advantages.of performing hideout return blowdown in the absence of sludge in; the tube sheet region was emphasize During all earlier fuel cycles..for Unit 1 and during the initial three cycles for Unit 2 blowdown from steam generators had been maintained at approximately 100 gpm and discarded as wastewater. An attempt was made to conserve water and thermal energy in Unit 2'during the fourth cycle by recycling blowdown water, after it passed through a demineralized cleanup system, back to the condense Recycling was discontinued during the:fifth_ cycle because-continuous boric- acid feed had been started. and the

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demineralizers were rapidly loaded by the relatively large (5-10 ppm) concentration of boric acid in the blowdown.- Water Chemistry Control Program The inspector reviewed the following elements of the licensee's. water chemistry ' control program: y staffing

training program quality control program

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laboratory facilities and analytical instrumentation chemistry control - ,

I The criteria used for this part of the inspection continued to be I Technical Specification requirements and guidelines developed by the Steam Generator Owners Group (SG0G) and the Electric Power Research j Institute (EPRI) for primary and secondary chemistry contro I (1) Staff 4 The composition and responsibilities of the staff of th Chemistry and Environmental Group were defined in Administrative Procedure FNP-0-AP-76, Revision 2 dated March 26, 1986. The inspector observed that Revision 2 had not altered the responsibilities of the non-radiological chemistry staff members who reported, through the Plant Chemist, to the Chemistry and Environmental Supervisor. Likewise, the supervisory personnel remained unchanged from the last inspection. The analytical j staff under the Plant Chemist and Laboratory Supervisors for i Units 1 and 2 consisted of twenty-five chemist / technicians who

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manned five shifts and four chemist / technicians who performed specialty functions on day shif At the time of this inspection, seven shift chemist / technicians' were contractors while eight new Alabama Power Company employees were being processed. Through' discussions with Chemistry supervisory and training personnel it was evident that the Chemistry Group had experienced considerable turnover of manpower during the past two year A review of the shift staffing showed that each of the five shifts had two Alabama Power Company chemist / technicians with two to four years longevity at the plant while the remaining shift members were new employees or contractors. The major adverse impact of this attrition rate appeared to the inspector to be in the area of training and overall stability of the shift (2) Training Through discussions with Chemistry supervisory and training personnel, the inspector reviewed activities related to the

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four-phase training and retraining program for members of. the Chemistry staff. Because of the extensive personnel turnover the training curricula- had to cover various phases of basic subjects as well as continuing and refresher training in state-of-the art analytical chemistry methodology. The training laboratory was also being used to extend the usefulness of such instrumentation as the ion chromatograph and total organic analyzer. The licensee's training program had been accredited-by'INP (3) Quality Control By means of an audit of control charts and discussions with the Plant Chemist and Quality Control' Specialist the inspector reviewed the measures being taken to maintain quality control of non-radiological chemistry analyses. Since the last inspection the Chemistry staff had begun to use. ion chromatography to determine parts per million (ppm) of boron and parts per billion (ppb) concentrations of chloride, fluoride, and sulfate in secondary coolant sample The licensee had initiated a crosscheck program with an outside-vendor. Samples were being provided periodically by this vendor to establish the chemistry staff's capability to accurately measure key chemistry variables in concentrations that were compatible with actual operating conditions and with the SG0G action level limit The chemistry staff was in the final phase of converting control .

charts to a statistical basis as opposed to the current use of '

absolute differences (percentages). The inspector considered this is to be a positive action that would facilitate the use of

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intra- and inter-laboratory samples for verification of accuracy, precision, and bias of result (4) Laboratories and Analytical Instrumentation The inspector observed that since the last inspection, the licensee had significantly increased its capability to monitor, diagnose, and control secondary water chemistry. The major change' had been the installation of new water chemistry control panels with associated inline analytical instrumentation for continuous monitoring of the most important chemical variables at six key sampling points throughout the secondary coolant system. Chemistry data were kept current through displays in digital and graphic form as well as on a common CRT scree Each monitor was equipped with an alarm that also displayed on the control panels in the secondary chemistry laboratory, and, for selected key parameters, on the unit's Control Room boar !

The inspector and chemistry staff personnel discussed in depth the advantages of inline monitoring for diagnostic and trending purposes as well as possible disadvantages associated with increased need for calibration and maintenance of the very sensitive analytical instrument In some cases, such as the new sodium ar,alyzer, the inline instrument could detect much lower concentrations of a chemistry variable than a " bench-top" instrument, and, thereby, complicate the quality control of the inline measurement The Chemistry staff was also routinely using state-of-art  ;

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" bench-top" instruments, such as ion chromatography, a total organic carbon analyzer, and an atomic absorption .

spectrophotometer for measurement of chemistry variables in grab l sample The chemistry staff was well equipped with analytical instrumentation needed to meet the stringent criteria of the SG0G guideline As this instrumentation has become more sensitive and complex the need for training and qualification of technicians and instrument engineers increased and should be  ;

considered by the license q (5) Chemistry Control

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This licensee was an early and active member of the SG0G and is {

considered to be fully cognizant of the many mechanisms of <

chemical induced corrosion that have been identified and )

investigated during the past ten years under the auspices of the l SG0G and EPRI. Consequently, during the four-year period of the l NRC Region 11 assessment of chemistry control the Farley units 1 have practiced chemistry control based on the best information I available from the NSSS vendor and from the SG0G/EPRI researc _ _ _ _ _ _ _ - _ _

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I However, as discussed earlier in this report, chemistry control has not been providing the degree of protection against aeneral corrosion of carbon steel components that will prevent wastage of these components and transport of iron oxide to the steam generators and, possibly, result in pipe failure. The key chemistry variables involved in general corrosion are pH (acidity) and dissolved oxyge The role of dissolved oxygen continues to be debated in light of the pipe failures that will be addressed in- Section 5 of this repor The inspector observed that the licensee was giving considerable attention to pH control under the constraints of both all volatile treatment (AVT) chemistry control, as recommended by the SG0G for protection of steam generator tubes, as well as the restrictions resulting from continuous boric acid injection, as recommended by the NSSS vendor for control of denting. If the licensee is successful in removing magnetite from the tube-tube support plate openings, thus eliminating the cause of tube denting, the restrictions placed on pH control by boric acid injection could be eliminated. There has been increasing evidence at PWRs within the NRC Region II that strict adherence to the SG0G guidelines can significantly reduce corrosion product transport, although not to the extent experienced in BWR The inspector concluded that the licensee was aware of all the concerns discussed above and was actively attempting to maintain the integrity of the primary coolant pressure bourcJary and the remainder of the secondary cooling syste Through audits of data acquired since the last inspection in January 1986 the inspector verified that the limits placed on primary coolant chemistry by the Farley Technical Specifications had been met and maintained. The absence of such corrosive contaminants as fluoride and chloride was attributed to the purity of the water produced by water treatment plant that was used throughout the reactor coolant system. The inspector and i chemistry personnel discussed information related to primary chemistry control that had been recently published by EPRI in an effort to minimize out-of-core radiation level No violations or deviations were identifie . Review of Licensee Actions Taken in Response to NRC Notices f IEN 86-106, Feedwater Line Break l Through discussions with cognizant members of the Systems Performance

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Engineering and the Chemistry and Environmental Groups the inspector reviewed the licensee's comprehension of the accident that occurred at the Surry Nuclear Plant in December 1986, and the erosion / corrosion mechanisms postulated as the cause of this accident. The inspector also reviewed the actions that had been

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12 taken in response to the Notice and Supplements that had been issued by the NRC relating to this accident. The inspector was informed that this Notice had been addressed principally by personnel in Southern Company Services (SCS). Theinspectorwasprovidedabfief-summary, developed at the licensee's corporate office on August 14, .

1987, of SCS analyses of pipe locations that were potentially, a susceptible to the type of erosion / corrosion observed at the Surry '

Plant. Ten points on Unit 2 were examined by ultrasonic testing while this unit was in an outage and three points on Unit I were examined while this unit was at power. NosignificantthinningiRas found. The current condition of pipes had been analyzed in terdr of the number of fuel cycles the pipes would maintain an acceptable level of integrity based on the maximum degree of wall thinning found during these tests. Additional inspections of single-phase piping were planned during the upcoming Unit 2 refueling outage as an extension of the normal inspection of two phase (steam) lines. SCS is developing a Secondary System Inservice Inspection Program / Plan for scheduling future examination IEN 86-108, Degradation of Reactor Coolant System Pressure Boundary Resulting from Boric Acid Corrosion The inspector was informed by the licensee that the potential for boric acid corrosion had been factored into plant surveillance and maintenance procedures prior to the issuance of this Notice. During refueling outage efforts are made to stop all known leaks and walkdowns of all systems are made before insulation is reinstalle Leakages are reported per Maintenance Work Requests. Administrative Procedure AP-52 had been revised to emphasize the timeliness of leak repair and removal of any boric acid that might have crystallized on steel surface Response to this Notice had oeen taken in conjunction v:ith the licensee's review of INP0 SOER 84- IEN 87-36, Significant Unexpected Erosion of Feedwater Lines The inspector was informed that Southern Company Services (SCS) was also taking lead responsibility for reviewing this Notic <

Currently, the inservice inspection program at Farley does not 1 include the additional pipe regions where thinning was identified at the Trojan Nuclear Plan SCS will develop a program for selecting inspection points for future surveillance of susceptible regions of straight runs of pip The scope of this program would not be established until the Notice could be completely evaluate i

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