IR 05000327/1988008

Insp Repts 50-327/88-08 & 50-328/88-08 on 880111-15 & 0125-29.No Violations or Deviations Noted.Major Areas Inspected:Layup & Preservation of Equipment

ML20150E507
Person / Time
Site:	Sequoyah
Issue date:	03/18/1988
From:	Elrod S, Walton G, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20150E506	List: IR 05000327/1988008 ML20150E503
References
50-327-88-08, 50-327-88-8, 50-328-88-08, 50-328-88-8, NUDOCS 8804010025
Download: ML20150E507 (17)

Text

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Report Nos.: 50-327/88-08, and 50-328/88-08 Licensee: Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2901 Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77, DPR-79 Facility Name: Sequoyah 1 and 2 Inspection Conducted: January 11 - 15, and January 25 - 29, 1988 Inspectors: II' e s w J. Yovk,'Se'nio VResi' dent inspector,

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' Date Sisned Bellefonte, Team Leader

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e m /7 /T G. W(Itorf, Yenipf Re'sident Inspector, Date Sigtied Watts Bar, Assistant Team Leader Team Members: W. Bearden oss Approved by: /f M hDate Sigiied 5. Errod, Secti'on Chief Division of TVA Projects SUMMARY Scope: This special inspection covered the Sequoyah program for the layup and preservation of equipmen Results: In the areas inspected, violations or deviations were not identifie PDR ADOCK 05000327 O DCD

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i REPORT DETAILS Persons Contacted l

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l Licensee Employees jt

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• S. Smith, Plant Manager '

• Biase, Maintenance Special Programs

1. • R. Briggs, Lead Materials Engineer

• R. Buchholz, Site Representative  ;

• C. Earls, Chemistry Project Manager  !

"G. Fiser, Chemistry Program Manager

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1. • D. Goetcheus, Chemistry Group Manager  !

l *T. Howard, Operations Quality Assurance Supervisor

• J. Johnson, Aquatic Biologist

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1. • G. Kirk, Compliance Licensing Manager r

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1. • C Landstrom, Licensing Engineer .

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• J. Maddox, Lead Engineer, Engineering Assurance  !

• J. Miller, Assistant Maintenance Supervisor l

"W. Nestel, Chemistry Program Manager  !

. *D. Pearson, Chemistry Engineer i

• N. Romano, Senior Maintenance Specialist

1. • E. S11ger, Manager of Projects

1. • R. Strickland, Chemistry Engineer

• J. Sullivan, Supervisor Plant Operations Review Staff- i

L Other licensee employees contacted included construction craftsmen, r i technicians, and office personne ;

j l 1 NRC Attendees  ;

"W. Bearden  !

i *W. Ross l *G. Walton {

4 #*J. York  ;

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* Attended exit interview on January 15, 1988 t i # Attended exit interview on Jaunary 29, 1988 i  !

l Exit Interview l t

l The inspection scope and findings were summarized on January 15 and ;

i January 29, 19!3, with those persons indicated by an asterisk in paragraph i j one. The inspectors described the areas inspected. Proprietary informa- ,

j tion is not contained in this repor No dissenting comments were ;

l received from the license i r

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l Note: A list of abbreviations used in this report is contained in j paragraph !

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3. Layup and Preservation of Equipment (92050, 79701)

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A layup and preservation team inspection was performed during the period

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January 11 - January 29, 1988, to review and assess the effectiveness of the licensee's program to preserve, during a period of inactivity, the i

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physical condition and operational ~ ability of components, systems, and !

selected structures of both Sequoyah units. The team was divided into two I i groups with one group emphasizing adequacy of the system layup according !

to industry standards and walking down systems tn determine if layup and T j preservation were performed to site procedures (paragraph 4). The second 1 group selected fewer systems and concentrated on integration of preserva-j tion requirements into the preventive maintenance (PM) program along with vendor preservation requirements (paragraph 5). A third area shared by both groups addressed the microtiological induced corrosion (MIC) portion of the layup and preservation program (paragraph 6).  ;

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l 4. Layup and Preservation of Equipment with Emphasis on Industry and Site

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j Background

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j This inspection was the third, and most comprehensive, review of the

actions being taken by the licensee to protect both the primary and t l secondary coolant systems from degradation since August 1985 when both units were shut down (see Inspection Reports 50-327, 328/86-14 i dated March 24, 1986, and 50-327, 328/87-33 dated June 8, 1987). ' Status of the Layup Program

- Because of the indefinite extent of the outages, the licensee had ,

I maintained both units in wet layup during most of the interim perio ;

. The conditions for wet layup had been based on chemistry control 1 guidelines developed and recommended by the Steam Generator Owners :

Group (SGOG) and the Electric Power Research Institute (EPRI). !

l The primary coolant systems of both units had been continuously :

l maintained under appropriate conditions to reduce corrosion of i

stainless steel pipe and components (pH of 4.5 to 5.2, dissolved !

oxygen less than 10 ppb, and a nitrogen atmosphere in the 7 j pressurizer). j l The secondary systems could not be maintained in similar conditions

! because of intermittent maintenance activities. During the initial i

} twelve months of the outage, major modifications of the steam 7 i generators, feedwater heaters, moisture separator reheaters, and ;

1 blowdown recovery systems had been performed. Consequently, the !

l hotwell, condensate and feedwater lines (including the tube side of I a the feedwater heaters) as well as the steam generators had been cycled several times +hrough filled and drained conditions. Main >

steam lines downstream of the isolation valves, extraction steam !

lines, and other carbon steel components of the feedwater heater i i

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drain and vent systems had remained in a drained condition since .

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shutdow When in wet layup, the steam generators had been protected from general c ~ rosion by ensuring 25-50 ppm of excess nydrazine was maintaine- to eliminate dissolved oxygen; by maintaining a pH of 10 to minimize acid corrosion; and by keeping a nitrogen atmosphere over the water, throughout the upper internals of the steam generators and in the main steam lines as far as the main steam isolation valves, During the layup period, the high pH of the steam generator water had caused dissolttion of coppe The copper had been transported earlier from the feedwater heater tubes and subsequently platcd out or "hidden" in crevices within the steam generators. The licensee had several times drained and filled the steam generators specifically to remove the dissolved copper and thus reduce future problems with steam generator tube dentin In March 1987 EPRI published guidelines for laying up plant systems in a dry (dehumidified) condition (Plant Layup and Equipment Preservation Sourcebook, EPRI NP-S-106) and recommended that consideration be given to dry layup of plants or systems that would be shutdown for extended period During the May 1987 inspection, the inspector had been informed that Sequoyah Unit I would be layed up dry, and that the necessary dehumidifiers had been ordere Unit 2 was to remain in wet layup in anticipation of restart.

Subsequently, the Chemistry Unit wat given responsibility for i designating a Layup Coordinator and for implementing dry layup of the entire secondary coolant (power conversion) system, except the Unit 1

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steam generator The plant's Maintenance Department was given responsibility for ensuring that an adequate preventive maintenance

(PM) program was developed to support wet and dry layup procedure In a concurrent program, the licensee was also implementing an erosion / corrosion assessment (Surveillance Instruction SI-704) that addressed the concerns expressed in NRC Inspection and Enforcement (IE) Notice 86-106. This program was designed to identify areas of the secondary system that might have been susceptible to degradation by erosion or corrosion during both plant operation and shutdow This program is discussed further in paragraph 6 of this report, c. Review and Assessment of the Unit 1 Layup Program Through discussions with the Layup Coordinator, review of pertinent Special Maintenance Instructions (SMIs) and Plant Configuration Drawings, and system walkdowns, the inspector assessed the protection against corrosion that was being given to the carbon steel piping and components in the secondary coolant syste .

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(1) Secondary System Dry Layup As discussed in Inspection Report Nos. 50-327, 328/87-33, the licensee had made the decision to layup all Unit 1 systems, except steam generators, in a draired and dehumidified condition. For thit goal the Layup Coordinator had divided all systems that carried water or steam (on both tube an.1 shell sides) into three major subsystems and began developing procedures (actually Special Maintenance Instructions) for providing "detailed steps for implementing dry layup ... through isolation, drainage, and the continuous purge of independent flow paths with dry air obtained from desiccant-type dehumidi-fiers."

The following three SMIs had been developed, and implementation had begun on the following schedule:

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SMI-1-2-1, Condensate and Feedwater Dry Layup Procedur Layup was started in July 198 SMI-1-1-6, Low Pressure Turbine and rieater Dry Layup procedure Layup was started in September 198 SMI-1-1-7, High Pressure Turbine / Heater Dry Layup Procedut Layup war started in November 198 Each of these procedures referenced specific Plant Configuration Drawings that had been used to establish subsystem boundaries and flow paths for the purging ai In each procedure a precaution section provided guidance to ensure operational and radiological safety measure, were taken. One measure required in stall atier. of high efficiency particulate (HEPA) filters on each dehumidifier process air outlet to prevent lithium chloride desiccant ca rryover into the lines being purge Another measure required that all temporary modifications be logged and that all equipment that was removed or clisassembled be tagged, properly stored, and logged. Further. the procedures required documer.tation of Permits, Hold Order >, and valve alignment Finally, the procedure required that each step be initialed as it was complete The comoletely documented procedure was retained by the Layup Coordir.ator who remained the point of contact for other plant personnel, e.g., Operations and Maintenance personne (2) Review of Flow Paths Through the use of Plant Configuration Drawings, the Layup Coordinator specified the placement of dehumidifiers, HEPA filters, and air exhaust points. These drawings were also used to determine multiple flow paths and specify methods to ensure

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I that each independent path had been purged until it was considered to be dry; i.e., to have less than 30 percent relative humidit The inspector and Layup Coordinator walked down the three major '

Unit I systems that had been layed up using SMI-1-1-7, SMI-1-1-6, and SMI-1-2-1. The Layup Coordinator identified principal and secondary exhaust points and demonstrated that, in all but one subsystem, the air contained significantly less than 30 percent relative humidity. As the result of this review, the layup conditions under which these systems were maintained were considered to reeet the EPRI guideline criteria and to be adequate for preventing general corrosion of the carbon steel  ;

piping, (3) Unit 1 Steam Generator Layup The inspector was informed that the steam generators in Unit 1 had been maintained in wet layup continuously since the NRC

inspection in May 1987. The inspector reviewed the current chemistry control data and observed that key parameters such as

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pH, hydrazine, sulfate, and sodium were within the licensee's administrative limits for steam generator water puri+.y. The

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concentrations of sulfste (40-70 ppb) and sodium (10-20 ppb)

were significantly less than the 1,000 ppb upper limit recommended by the SGOG to reduce corrosio (4) Reactor Coolant System Layup As discussed in previous inspection reports, the Unit I reactor coolant system had remained filled with borated (but not lithiated) water since plant shutdown. Since lithium hydroxide had not been used to control pH, the reactor coolant pH had remained slightly acidic (pH of 4.7) throughout the shutdown period. The licensee's program for protecting the stainless steel components of the reactor coolant system was considered to be acceptabl (5) Comoonent Coolirg Water System Layup This closed cycle system had been maintained in a filled condition. The water was being treated with sodium molybdate to prevent corrosio d, Review and Assesstnent of the Unit 2 Layup Program Through discussions with cognizant licensee personnel and an audit of recent chemistry control data, the inspector assessed the effective-ness of the layup conditions being used for the primary and secondary coolant systems of Unit .

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8 (1) Primary Coolant System Layup +

Throughout the entire shutdown period, the primary coolant system had been filled with borated water with low concentrations (approximately 10 ppb) of dissolved oxygen. Sufficient lithium hydroxide (approximately 1 to 2 ppm) had also been added to maintain the pH nearly neutra ;

Instead of the normal hydrogen overpressure used during plant operation, the pressuri:er gas space had been filled with nitrogen to eliminate the presence of ai (2) Secondary System Wet Layup The licensee had considered dry layup of all of the secondary coolant system, except the steam generators, but had chosen to continue the wet layup conditions that had been in effect during most of the shutdown period. These current conditions are ,

summarized as follows:

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(a) Condenser /Hotwell  !

The hotweil was filled with demineralized water with i sufficient hydrazine to maintain the pH at 8.8-9.2 and the dissolved oxygen level below 100 pp During the inspector's previous site visit in May 1987, the desired dissolved oxygen level could not be maintained because the turbine / condenser was open to air. In the interim period ,

the licensee had isolated the condenser and had established I sufficient condenser vacuum (by means of the plant's -

auxiliary boiler and the condenser air ejector) such that l the level of dissolved oxygen in the hotwell water was ;

being kept below 10 pp i

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(b) Condensate /Feedwater Corrosion control of the carbon steel pf ping of these

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systems was being accomplished by cycling the hotwell water (by means of hotwell pumps) through the "short cycle,"

1.e. , through the condensate lines, condensate polishers and feedwater lines to the discharge of the Number 4 heaters and then back to the hotwell. The remainder of the feedwater lines upstream of the main feed isolation valves, were also filled with chemically treated water, but could not be cycled continuously through the "long cycle" because [

of a design problem associated with the steam generator l layup configuratio The inspector waA informed that in November 1937 the licensee took advantage of a shutdown of the steam generator 16 yup system to actuate "long cycle" cleanup. Although the purity of the water in the hotwell l

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had been c.iminished briefly, the condensate polishers quickly restored the water in the entire "long cycle" to the desired level. This indicated that only low levels of oxidation (corrosion) products had been present in the entire condensate /feedwater system, including the tube sides of the seven sets of feedwater heater As reported previously, the copper alloy tubes in Feedwater Heaters 1 and 2 had been exchanged with stainless steel tubes, thereby increasing their resistance to corrosio (c) Feedwater Heaters The shell side of the low pressure and high pressure feedwater heaters and the moisture separator reheaters had

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been drained at shutdown in August 1985 but were not in a layup or dehumidified condition.

l- e. Sequoyah Pipe Wall Degradation Monitoring Program l In response to concerns about the integrity of the secondary water l system, that were expressed in Inspection Report Nos. 50-327, 328/87-33, the licensee provided a list of actions to be taken to assess the condition of these systems before startup of each Sequoyah unit (see letter from R. Gririley to the NRC dated July 29,1987). In part, these actions consisted of the development of surveillance procedures for use before and after startup. Two of these procedures were reviewed by the inspector during this inspectio $1-714 Extraction Steam Pipe Wall Degradation Monitoring Program, Rev. O, June 26, 198 SI-733, Wall Degradation Mor.itoring Program for the Feedwater/

Condensate Piping, Turbine, and Heater Drain Lines, Rev. O, July 24, 198 Both of these surveillances consisted of ultrasonic testing of localized areas of piping to monitor pipe wall thinning. Althougn impetus for the development of this surveillance program h6d resulted from erosion /correston problems in the industry (see IE Notice 86-106), the program also was to be used to establish criteria for operability of these systems after the extended shutdown perio The expanded surveillance program and associated preventive maintenance activities we e considered to guard against wall thinning as long as the tests covered regions that might be susceptible to corrosion during the extended outage (i.e., low points, dead legs or other stagnant or low flow regions) as well as regions susceptible to erosion / corrosion under conditions of higher flow, turbulence, or temperature, l

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8 Conclusions The current layup conditions for Unit I were considered to afford state-of-the-art protection against corrosio Limited visual examinations of the interior of the carbon steel piping in the secondary coolant system did not identify degradation caused by wet Iryup or "drained but not dried" conditions during the initial two years of the extended outag An expanded surveillance program of ultrasonic examinations of the secondary coolant system will be performed prior to and af ter startup of this uni Because of uncertainties related to Unit 2 startup, the low and high pressure piping, drains, vents, etc., in this unit had remained in either a filled or "drained but not dried" condition for years. Audits made during three inspections during this extended outage showed that wet layup conditions, when in force, often did not meet the criteria recommended by the SG0G/EPRI for protection against corrosion. However, data obtained by the licensee during a

"long-cycle" cleanup of the hotwell/ condensate /feedwater pipes in November 1987 were indicative of low levels of rolid or soluble impurities and thereby, insignificant corrosive attack of the carbon steel piping. The integrity of these pipes has been, and will continue to be, monitored by the expanded ultrasonic testing progra . Program Inspection Emphasizing Vendor Requirements and Preve.t;ve Maintenance The inspectors selected for review eight components or groups of similar components from a list of Unit I safety-related components and requested that the licensee provide evidence of performance for selected preventive maintenance (PM) requirements associated with these components. In all cases the licensee provided adequate evidence of perfe.'mance of the stated preventive maintenance requirement. In some cases the documentation as requested was not available but the licensee was able to provide evidence that the PM requirement had been satisfied as part of a newer PM instruction due to the older instruction being cancelled and incorporated into another instruction. The following PM requirements were reviewed for technical adequacy and evidence of completion:

1-PMP-003-142, Turbine Driven Auxiliary Feedwater Pump, Routine Equipment Rotatio MTRA-067-0456-B, ERCW Pump P-B, Sample and or Replace Pump Lubricatio MV0P-067-2978, Upper Containment ERCW Isolation Valve, Lubricate Valv CLR-063-144, Safety Injection Pump 011 Cooler, Inspect ERCW Heat Exchange .

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1-FCV-001-VAR, Various Main Steam Isolation Valves. Lubricate Valve PMP-024-185, RCW Booster Pump B, Inspect Pump Packin FCV-065-28A & 0-FCV-065-28B, EGTS Train A Ccoldown Valves, Cycle Valve FCV-999-VAR, Various Liraitorque Valve Operators, Inspect Valve Operator Additionally the inspectors reviewed the licensee's program for motor and equipment rotatio This program is necessary to prevent rotating equipment from remaining idle for extended per'.ods, especially during plant shutdown. Damage to bearing surfaces could result under these conditions due to lack of lubricatio The inspector determined from review of completed records, that the licensee Fad an adequate program which provided for routine equipment rotatio Surveillan e Instructions SI-699.1 and SI-699.7, Unit 1 and 2 Monthly Equipment Rotation, require that each piece of equipment be rotated by one of the following means:

Verification from logs or other records that a particular component has been operated during that month Swapping between redundant equipment Hand rotation of equipment that can not be otherwise operated All areas reviewed were found acceptabl The inspectors toured selected areas of both Units 1 and 2 and observed the plant status with regard to layup and preservation of equipment. In addition, the inspectors met with the licensee personnel responsible for layup and preservation of equipment. Since Unit 2 is presently in a planned start-up mode, no further inspections were conducted on Unit On Unit I the inspector observed that the secordary non-safety-related systems were in dry lay-u?, except the steam supply from the main steam line to the tv-bine driven auxiliary feedwater pump. The licensee advised that the valve was closed, and tagged, and the line was draine The inspector requested a low point drain valve be opened on the main steam system to verify the line was dry. The inspector was present when the licensee opened the drain valve. No water was presen The inspector interviewed the licensee's on site Quality Assurance Auditors to determine the adequacy of the licensee audit on layup and preservation of equipment. The on site auditors advised they had not performed independent audits, but Corporate QA had audited the program in the Spring of 1986. Further, the area was scheduled for a second audit two years from the Spring 1980 .timef rame. The inspector obtained copies of the corporate QA report and reviewed the findings and corrective

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actions implemente The audit report indicated the review was thorough, and identified some problems in the chemistry control area. The licensee implemented adequate corrective action All areas reviewed. by the inspector were acceptabl . Microbiological Induced Corrosten Summary of Meeting in Bethesda t

A presentation was made by TVA to the NRC on the microbiological induced corrosion (MIC) program for Sequoyah on December 15, 1987. Following is the TVA summary for that presentation:

The structural attack of stainless steel butt welds in the Essential Raw Cooling Water (ERCW) system has been the most significant problem associated with M1C during inspections at Sequoyah. To address this ,

problem, Sequoyah has developed a program to inspect for leakage, evaluate the damage, and repair as required. Also, Sequoyah will .

perform an ongoing investigation of corrosion damage in these welds  !

to monitor this damage and subsequently verify the effectiveness of ;

water treatment when the new water treatment progran is implemente i Site Insptetion of MIC Program i

' Stainless Steel MIC Procram i

During this inspection, the inspectors walked down all of the  ;

stainless steel piping in the ERCW System for both unit MIC i attacks occur at butt welds in the stainless steel piping system Originally there were 405 butt welds for both units (new and additional welds are added as sections of pipe with leaking welds are replaced). Of the 405 welds, 67 were radiographed to determine if MIC damage was present. Of these 67 welds, 28 were leaking. When removing the 28 leakers, sections of pipe with more welds than those leaking were removed and the licensee examined most of these additional welds. Three additional welds in the ERCW were found to leak after December 15, 1937, and before start of heat up of Sequoyah Unit 2 to Mode 4 All of the known le6 king welds were repaired  ;

before the start of heat up. The ERCW pipe is 316 stainless steel, but the weld metal at 504uoyah is type 308. While the percentage of Chromium is approximately the same for both alloys, clloy 316 has much higher Molybdenum for increased pitting resistance. This higher alloy content is postulated to make the base metal cathodic and the .

weld anodic. A large cathode and a small anode is not desirable from l a corrosion standpoint. All new welds at Sequoyah for the ERCW stainless steel piping will be 316 weld meta In comparison, the ERCW pipes at Watts Bar are alley 316, but they are welded with 316 weld metal. No MIC attack was noted in the i

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cor. parable welds at Watts Bar. One stagnant leg in the stainless steel system at Watts Bar did have MIC attack on some of the weld '

Of the 405 welds examined, approximately 85 were in 3 in. diameter piping (others were in the C in, diameter piping 1 and no leaking was i found in these welds. The flow velocity may have been greater in the smaller pipe Therefore, the presence of MIC attack may be influenced by a combination of weld metal and flow rate (literakure indicated flow rate is definitely a factor).

The licensee has committed to walk down and visually inspect all of welds on the ERCW stainless steel piping every six months. The following four PM documents are used for identifying the welds:

- PM 2220 - Unit 2, ERCW Supply Piping

- PM 2221 - Unit 1, ERCW Return Piping

- PM 2222 - Unit 2, ERCW Return Piping

- PM 2223 - Unit 1, ERCW Supply Piping Originally the supply and return piping for each unit were placed on a separate PM number in order to spot any trends in leaking. Since the return lines are warmer, it was anticipated that the rate of pitting would be greater and thus more leaking welds would be present. Actually, a few more leaking welds were found in the supply line If any leaking welds are found during the semi-annual inspections or i during routine daily walkdowns required by Sequoyah housekeeping :

procedure (SQA-66), the welds in the stainless steel ERCW lines will be evaluated by 'echnical Instruction TI-109, "Nondestructive Testing ,

of Stainless Steel Butt-Welds to Assess Damage Resulting from ;

Microbiological-Induced Corrosion (MIC)". This technical instruction

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addresses rzdiographic testing of butt welded stainless steel piping for potential M!C damage. The licensee states that the results cf this testing will be used to trend rates of weld degradation, determine the necessary corrective actions, and quantify the effect The licensee stated that this TI (Rev.1, dated August 28, 1987)

would be revised to remove the ultrasonic testing (UT) option for evaluating defect length. Ultrasonic testing for MIC damage, when compared to sectioned samples, does not give the desired accurac During the presentation in Bethesda the licensee committ6J to changing PMs 2220 thru 2223 and TI-109 so that when a leak is discovered, tne following actions will be taken:

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During Modes 5 and 6 the recair work will be a restart requiremen During Modes 1, 2, 3, and 4 TI-109 will be used to evaluate corrosion damage (by radiography), and the instruction will be revised to specify that this will occur within seven days after !

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di scovery of the lea This data will be compared against specific criteria and if this is exceeded a detailed seismic analysis will be performed within an additional seven days. The licensee's experience indicated that all of the data at Sequoyah (from the 67 radiographed welds) have been-within the screening criteria, but should the seismic analysis be evaluated as structurally inadequate, appropriate Technical Specification actions will be take If the leaking welds found are determined to be structurally sound, appear to have very little leakage, and do not have the potential for leaking on safe shutdown equipment, then they will be scheduled for repair at the next outage. These welds will be noted in preventative maintenance (PM) document 2240 for Unit 1 and PM 2241 for Unit These PMs require that a radiographic evaluation be performed per TI-109 on a quarterly basis until the leaking welds are fixed or replaced. The welds listed on revision 0 of these two PMs have all been cut out so any new leaking welds found during operation will be added to these documents. During the MIC presentation, the licensee stated that six to ten welds, some with MIC damage and some new welds, would be monitored to determine growth of MIC indications and development of new indications. This monitoring will continue until <

an ef fective water -treatment is in picc These welds will be monitored under PMs 2240 and 224 The inspectors reviewed Design Change Notice No. X00073A which dealt with the licensee's concern that if a seismic event took place and MIC damage were in a weld that water could be sprayed on class 1E equipment and affect the safe shut down of the reactor. The licensee located these areas on the ERCW stainless steel piping and placed individual spray protection bor's over each weld. The inspectors observed the location of these boots and the electric equipment during the walkdown of the stainless steel ERCW pipin The boot consists of a silicone rubber fabric reinforced with fiberglass. The seams and ends of the boot are sealed with Dow Adhesive No. 732. The ends of the boots are clainped with stainless steel bands. A plastic fitting in the boot with plastic tubing attached diverts any leakage inside the boot away from class 1E electrical equipmen . Carbon Steel MIC Program Although the presentation at Bethesda by the licensee indicated that the only problem identified with carbon steel was flow restriction, some thru wall pitting has been observed at Sequoyah in both safety-related and non-safety-related system Following is a summary of this experience at Sequoya (1) Leakage History

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(a) Essential Raw Cooling Water (ERCW) Piping - 3 Leaks (All

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One sample was analyzed, one sample was lost for analysis purposes, and one sample is currently at the Singleton Materials Engineering Laboratory for analysi !

(b) High Pressure Fire Protection (HPFP) - 2 Leaks One was in an Office Building adjacent to a hose station, the other was in an Auxiliary Building bypass line from the storage tank (7 th-u-wall holes were present)

(2) Ultrasonic Grid Experience (a) Essential Raw Cooling Water SI-704 has 30 grids (30 pipe areas with grid networks) for cavitation evaluation. None show pitting damage, even in grids which are normally in stagnant flow areas and which do not have active cavitatio (b) High Pressure Fire Protection The licensee has currently tested 13 Grids - No wall thicknesses were less than the nominal wall thicknes (c) Raw Service Water (Non-Safety-Related)

2 Grids were Tested:

- One was on a pipe adjacent to a leaker, (0-SW-1).

No measurements were less than nominal wall thicknes .The other was on a storage tank. Nominal wall thickness was 0.25 in. The measured minimum thickness was 0.21 1 The acceptance criteria is that actual thickness cannot vary more than 12.5 percent less than nominal thickne, This condition was 16% less than nomina (d) Raw Cooling Water (Non-Safety-Related)

2 Grids were tested. One had no damag No. 2-RCW-1 had damage in 4 in. diameter piping. The acceptance limit was 0.237 in. The wall thickness found was 0.15 in to 0.25 i (3) Other (Non-Safety-Related) Experience Raw Service Water (RSW) Piping Samples removed as part of modifications projects:

- During part of one of the RSW modifications, the licensee

' found up to 46% pitting depth.

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During another RSW modification, the minimum piping thickness found was 0.220 in., and the nominal wall thickness was 0.322 in. The acceptance criteria was that the minimum wall thickness cannot be more than 12.5 percent less. than the nominal thicknes This measurement was 31.6% less than the nominal wall thicknes The inspectors reviewed Engineering Assurance audit deficiency No. 86-26-03 which states that no evidence was found that an evaluation of internal corrosion was performed by the Sequoyah Mechanical Design Project as part of TVA's commitment to paragraph C.2 of Regulatory Guide 1.29. Part of the answer to this deficiency (memorandum No. B25871117 016) stated that a report entitled,

"Corrosion in Carbon Steel Raw Water Piping", had been submitted to the NRC. In addition, the memorandum stated that TVA continues to evaluate the effect of corrosion on carbon stee In the Quality Information Release attached to this memorandum for i answering the deficiency, the grid systems used for monitoring and on some of the leakers mentioned in the preceding information were

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discusse Several of the points mentioned were:

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leaks in carbon steel had been occasionally identified and in each case, ultrasor.ic (UT) mapping found the leak was caused by discrete pits without large areas of degradatio All of the leaks in carbon steal have resulted in a steady drip instead of a spray, because the heavy build up of corrosion in the pit tends to restrict the opening and prevent sprayin The Quality Information Release gave the following information as a summary and conclusion:

"The experience of TVA has been that carbon steel piping may periodically develop leaks which result from through wall pits.

I However, gross wall loss that would greatly compromise the piping integrity has not been identified. The category I(L)

l piping may cause problems resulting from unanticipated leakage, but gross pipe failures resulting from excessive corrosion

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thinning is not expected to occur, even in a seismic event.

l l Individual pits are difficult to locate (in carbon steel) using ultrasonic test technique A large area of piping may test without identification of damage, but random pitting can occur in any untested are This indicates that the only reliable method of identification of pitted areas is by leakage detection."

Several recommendations were mentioned in the release stating that trending, generic applicability, and testing of each leaking area should be performed. Also, a technical instruction for carbon steel l

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(such as TI-109 for stainless steel) will be generated to document the methodology and frequency of the- inspections. The licensee stated that this TI was scheduled to be in place by August 198 Development of a Biocide The inspector met with the licensee to discuss their program for the  !

' development of a water treatment method using a biocide to prevent or r minimize MIC attack on piping and welds. Long term, this is a very important part of the MIC progra Initially the engineering group (Knoxville) had recommended Biosperse ,

305 as the biocid However, a corporate chemistry group (Chattanooga) has recommended considering the following:

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Nalco Company's Actibrom 1338 is a liquid solution containing sodium bromide and a biodispersen This compound would be injected simultaneously w';h sodium hypochlorite into the ERCW system (sodium hypochlorite is currently being injected year round into the ERCW system).

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Betz Company's Slimicide C78P is a granular organic material that releases both chlorine and bromine when dissolved in wate Calgon Company's H950 is a liouid solution of sodium bromide and would be injected simultaneously with the sodium hypochlorite into the ERCW syste Where applicable, these products have Environmental Protection Agency (EPA) certificates and have been corrosion tested for most of the alloys that they would be in contact with in the ERCW system. Some compounds use a surfactant, which is a wetting agent, that improves

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the efficiency or allows penetratica by chlorine or bromine, and some

compounds use dispersents which attempt to eliminate the deposits

left in the pipes since seme bacteria concentrate under these deposits.

, The chemistry group is coordinating development activities with Engineering and other groups within TV All of these activities were in the planning stage at the time of the inspection and an

! approximate target date to have this system in effect is

October 1988.

t The ERCW system is intended to have its own biocide injection syste '

The Condensate Cooling Water (CCW), Raw Cooling Water (RCW), RSW, and the HPFP systems will share a separate injection syste The ,

, Sequoyah site chemistry department is handling the planning for the

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water treatment MIC protection for the CCW, RCW, RSW and the HPFP l

systems. The site group is evaluating Betz Company's Clam-trol CT-1 for protection against MIC and for clam contro ,

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l 16 l Visit to Singleton Material Laboratory (Maryville, TN)

The TVA Singleton Materials Laboratory is performing the metallurgical failure analyses for the MIC problems, and is performing corrosion tests of materials. A discussion was held with the laboratory personnel about past failure investigations and some MIC samples that were currently being evaluated, e.g. , a two inch diameter carbon steel elbow with a MIC thru wall penetration in the socket weld and a four inch diameter carbon steel straight pipe section out of the High Pressure Fire Protection Syste Another area concerning the MIC program at the laboratory involves the corrosion testing facilities. One once-through loop would test the metallurgical specimens in raw lake water onl The laboratory does not have a permit to dump chemicals into the lake. Two closed l loops would test various biocides. A number of base metals, weld metals,-and combinations will be tested within the.next six months to a year to support the MIC water development program. The inspector reviewed in part the following procedures that will be used io this testing:

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Procedure N SME-CORL-9, Rev. O, "Measurement of the Corrosivity and Fouling Characteristics of Raw Lake Water",

dated December 1, 198 Procedure No. SME-CORL-10, Rev. O, "Method For Dispersion /

Biocide Test on Stainless Steel or Carbon Steel Pipe", dated November 1, 198 Procedure No. SME-CORL-11, Rev. O, "Method For Determination of Corrosivity of Biocides To Metals In Raw Water Systems", dated November 24, 198 Within this area, no violations or deviations were identifie . List of Abbreviations, Units 1 and 2 CCW - Condensate Cooling Water EPA - Environmental Protection Agency EPRI - Electric Power Research Institute ERCW - Essential Raw Cooling Water HEPA - High Efficiency Particulate HPFP - High Pressure Fire Protection IE - Inspection and Enforcement MIC - Microbiological Induced Corrosion PM - Preventive Maintenance RCW - Raw Cooling Water RSW - Raw Service Water SI - Surveillance Instruct'on e.g., SI-704 SGOG - Steam Generator Owners Group SMI - Special Maintenance Instruction UT - Ultrasonic Testing