IR 05000338/1986014

Insp Repts 50-338/86-14 & 50-339/86-14 on 860505-09.No Violation or Deviation Noted.Major Areas Inspected:Plant Chemistry

ML20211B568
Person / Time
Site:	North Anna
Issue date:	05/21/1986
From:	Ross W, Stoddart P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20211B558	List: IR 05000338/1986014 ML20211B554
References
50-338-86-14, 50-339-86-14, NUDOCS 8606110740
Download: ML20211B568 (9)

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\...../ MAY 2 71986 Report Nos.: 50-338/86-14 and 50-339/86-14 Licensee: Virginia Electric and Power Company Richmond, VA 23261 Docket Nos.: 50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection Conduct d: May 5-9, 1986 Inspector: . 14flA1- ( Je [d W. J. p Date Signed Approved by: - M'- f '

P. G. Stodda % Acting Section Chief Date Signed Emergency Preparedness and Radiological Protection Branch Division Radiation Safety and Safeguards SUMMARY Scope: This routine, unannounced inspection concerned plant chemistr Results: No violations or deviations were identifie DR 860527 ADOCK 05000338 PDR

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REPORT DETAILS Persons Contacted

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Licensee Employees

• E. W. Harrell, Station Manager G. E. Kane, Assistae.' Station Manager

• E. R. Smith, / ,s . tant Station Manager

• J. A. Stall, aperin . dent, Technical Services P. Hensley, Su,o- .sor, Water Treatment

• L. Miller, Supervisor, Chemistry L. Lee, Assistant Supervisor, Chemisty P. Naughton, Engineer, Inservice Inspector L. Johnson, Corporate General Office L. Jones, Corporate General Office J. Ogren, Corporate General Office Other Organizations L. Becker, Westinghouse NRC Resident Inspectors L. King

• Attended exit interview Exit Interview Ihe inspection scope and findings were summarized on May 9, 1986, with those persons indicated in Paragraph 1 above. The inspector described the areas inspected and discussed in detail the inspection findings. No dissenting comments were received from the license The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspector during this inspectio . Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspectio . Plant Chemistry (79502 and 79701)

As a result of its continuing concern for steam generator tube integrity, the NRC staff recently issued recommended actions and review guidelines directed toward the resolution of unresolved safety issues regarding this subject (See Generic Letter 85-02 dated April 17, 1985). One recommended action is as follows:

" Licensees and applicants should have a secondary water chemistry program (SWCP) to minimize steam generator tube degradation. The

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specific plant program should incorporate the secondary water chemistry guidelines in the Steam Generator Owners Group (SG0G) and Electric Power Research Institute (ERPI) Special Report EPRI-NP-2704, "PWR Secondary Water Chemistry Guidelines," October 1982, and should address measures taken to minimize steam generator corrosion, including materials selection, chemistry limits, and control method In addition, the specific plant procedures should include progressively more stringent corrective actions for out-of-specification water chemistry conditions. These corrective actions should include power reductions and shutdowns, as appropriate, when excessively corrosive conditions exist. Specific functional individuals should be identified as having the responsibility / authority to interpret plant water chemistry information and initiate appropriate plant actions to adjust chemistry, as necessar The reference guidelines were prepared by the Steam Generator Owners Group Water Chemistry Guidelines Committee and represented a consensus opinion of a significant portion of the industry for state-of-the-art secondary water chemistry control."

Reference Section 2.5 of NUREG-0844 In parallel action, the NRC Office of Inspection and Enforcement has developed two new Inspection Procedures to verify that the design of a plant provides conditions that ensure long term integrity of the reactor-coolant pressure boundary and to determine a licensee's capability to control the chemical quality of plant process water in order to minimize corrosion and occupational radiation exposur The objectives of these new procedures were partially fulfilled during previous inspections (See Inspection Reports 50-338 and 339/84-24 dated July 11, 1984 and 50-338 and 339/85-09 dated April 18, 1985). This followup inspection was a further assessment of the degree to which the integrity of the steam generators had been maintained during the past year as well as a review of the licensee's response to Generic Letter 85-02. The inspector reviewed the effectiveness of both the design of the secondary system and the licensee's chemistry control program, Integrity of the Primary Coolant Pressure Boundar Since the last inspection in this area Unit I had completed its fifth fuel cycle (November 4, 1985), and had begun the sixth fuel cycle December 27, 1985. During this period Unit 2 had undergone its fourth refueling outage (February 21 - April 2, 1986). In August 1985, a primary to secondary leak was observed in the "A" steam generator in Unit 1, and this unit was shut down while 280 steam generator tubes were inspecte Thirteen tubes had reportable indications, most of which were at the locations of the lower tube support plate Likewise, one leaking steam generator tube was observed in Unit 2 on

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April 18,1985, and resulted in a one-day outage. Because of the tube degradation observed in August in Unit 1, the licensee performed a 100%

eddy-current inspection of the tubes in the three steam generators during this unit's fifth refueling outage. This inspection revealed additional indications of cracking in the tube support regions (predominantly on the hot leg side of the first four tube support plates). Most of these cracks exceeded 80% +.o 90% through wall (one leaker was observed in "C" steam generator) and required pluggin Subsequently, during the normal eddy-current testing of the Unit 2 steam generators, nine tubes were plugged because of deep (mostly >90%

through-wall) indication All three generators had cracked tubes; however, as was the case with Unit 1, there were many more cracks in

"C" steam generator, including three tubes that had three to seven indicators in each. These inspection results were reported to the NRC (Letters to Dr. J. Nelson Grace dated December 27, 1985, and April 11, 1986).

The cracked tubes appeared to be randomly distributed, as were those previously plugged; i.e., a total of 111 tubes in Unit 1 and 12 tubes in Unit 2. (All Row 1 tubes had also been plugged.) Where multiple indications were observed, all were at the levels of tube support plates. The licensee correlated the cracking mechanism with the denting phenonmenon that had been encountered in the early fuel cycles of both units. The apparent rapid growth of the cracks was attributed to the masking effect of the magnetite in the tube holes that had been associated with the denting process; i.e., the cracks may have been initiated early but were not detected by eddy-current testing until a threshold depth was achieve The licensee had been adding boric acid to the feedwater for several years in an effort to retard the formation of magnetite in the tube support holes and thus reduce denting. A steam generator study group had been formed to determine if other means could be used to prevent denting, to remove magnetite from the tube holes, to remove stress from the outer and inner diameter walls of the tubes, and terminate the initiation and propagation of stress induced crackin No additional eddy-current testing is planned before the next refueling outages (>l year) when two of the three steam generators in each unit will be inspected by full-length eddy-current testing of 20% of the tubes in each steam generator. The inspector discussed the possibility that in the interim period additional tube leaks might be encountered if cracks already existed but were masked by the magnetite in the tube-sheet hole Protection Provided by Plant Design Through audits of chemistry control data and discussions with licensee ,

personnel, the inspector reassessed the protection against corrosion of l the steam generator tubes provided by the secondary coolant syste , .

During the 13-month interval since the inspector's previous site visit, Unit I had undergone a seven week refueling outage in November -

December 1985, a two-week outage for steam generator tube repair in August 1985, six short power outages of one to six days duration, and five brief (<1 day) power reductions. The operating history of Unit 2 included a six-week refueling outage in the Spring of 1986 and six shutdowns for periods of one to four days. In addition, Unit 2 was used in a load following mode and underwent several power transient A comparison of plant operation with trends in key chemical variables indicated that the relatively unstable operation of both units did not affect secondary water chemistry significantly except when the temperature of the steam generator water decreased, as during a unit shutdown. The licensee used controlled shutdowns to reduce hideout return through blowdown of the steam generator water and, thus, to decrease the concentrations of corrosive impurities in the steam generator The primary source of contaminants had historically been attributed to inleakage of condenser cooling water and air through the main condenser The inspector was informed that inleakage of water had been reduced to a point where it was difficult to establish if ingress of relatively clean water from Lake Anna continued. This improvement l was achieved by throttling the flow of condenser cooling water during the colder winter months, thereby controlling the level of vacuum in the condenser to a level that would not result in leak The licensee continued to have difficulty reducing air inleakage in both units to less than 10 standard cubic feet per minute (SCFM).

During the past year, air inleakage varied between 10 and 30 SCFM, although Unit 2 condenser inleakage during this inspection was being maintained between 6 and 10 SCFM. A " condenser tightening" program had been initiated in a effort to reduce both water and air ingres The licensee had also continued to have problems with the water treatment plants that provide condensate makeup for the two units. The flash evaporators had not been sufficiently efficient to achieve the design output for both units. Also, the water stored in the condensate storage tanks and the emergency condensate storage tanks was exposed to air and therefore contained high concentrations of dissolved oxyge During this inspection the licensee was relieving the strain on the water treatment plant by recycling approximately 55 gpm of blowdown from Unit 2. Rather than valving this blowdown to waste, as had been normal for both units, part was being cooled and purified by passage through a spare radwaste demineralizer. The demineralized water was then being pumped to the Unit 1 Condensate Storage Tank (CST) for reus The inspector was informed that studies were in progress related to making this blowdown recovery system permanen The licensee was also giving consideration to contracting for a mobile water treatment plant (possibly a reverse osmosmis system) to be installed onsite to augment or replace the output of the flash evaporator system Likewise, additional water treatment

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processes were being investigated for the removal of the large (>2000 ppb) amounts of total organic carbon (TOC) found in the lake water which supplies the water treatment plan The conder. sate polishers were being operated in the same manner as-during the inspector's last site visit. Approximately 1,000 gpm of condensate was being valved through one demineralizer unit while the remaining units were in a pre-coated standby condition. However, during this inspection one demineralizer unit in each system was down for maintenance. An audit of chemistry data shcwed that this procedure was producing feedwater of high purity, i .e. , cation conductivity of 0.15-0.20 umhos/cm in Unit 1 and 0.10 to 0.15 umhos/cm in Unit (Part of this conductivity was attributed to carryover of boric acid from the steam generator). During previous inspections the inspector had been informed that full-flow polishing could not be achieved at high power levels because the condensate booster pumps could not overcome the pressure drop across four demineralizer units. However, during startup of Unit 2 frofa its last refueling outage, full-flow polishing was maintained until the unit reached 100% powe The inspector used the following three parameters to assess the vulnerability of the steam generators to degradation through corrosion mechanism * Purity of steam generator blowdown - Audits of chemistry control data showed that during the past year, whenever the units were operating in a stable mode, all key chemical variables in the steam generator blowdown were within the limits recommended by SG0G/EPRI. The pH of the water in the steam generators was 7.0 to 7.5 because the licensee continued to maintain boric acid in the steam generator water at a concentration of 5 to 10 ppm to retard dentin The SG0G/EPRI guidelines recommend a more alkaline environment (pH of 8.5 to 9.0) to minimize corrosion of carbon steel component * Hideout return - Although the licensee had reduced the inleakage of contaminants into the condensate, it was evident that during the past year significant amounts of chloride and sulfate salts remained in the steam generators. Such " hideout" impurities were identified and measured when the water in the steam generators was cooled and the solubility of the " hideout" salts was increase Through use of its computerized data management system, the licensee was able to correlate power transients (particularly shutdowns) to increases in the concentrations of chloride, sulfate, silica, and sodium in the blowdown - as well as cation conductivity. As discussed below, the licensee had revised plant cooldown procedures to provide time for " soaking" the steam generators at 350*F to blowdown the solubilized hideout retur During controlled shutdowns, the concentration of sulfate in the

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blowdown exceeded 2 ppm in Unit I and 1 ppm in Unit 2 while chloride was as high as 300 ppb in Unit 1 and 40 ppb in Unit The licensee attributes these concentrations of potentially corrosive anions (and equivalent concentrations of sodium) to condenser leaks in the past as well as from leakage of powdered ion exchange resin from the condensate polisher * Steam generator sludge deposits - During sludge lancing of the steam generators in the most recent refueling outages, a total of 2150 pounds of sludge was removed from Unit I and 287 pounds from Unit 2. This sludge was predominantly oxides of iron; however, copper was also present, especially in Unit 1. (Both Units have feedwater heaters fabricated from a copper alloy). Equally large amounts of sludge had been removed during the previous refueling outage Since the licensee's startup procedures provided for thorough flushing of both the low pressure and high pressure pipes of the secondary system before feedwater is pumped into the steam generators, it is evident that large amounts of non-adhesive iron oxide were formed during the most recent (18 months) fuel cycl It also appeared that the carbon steel pipes in Unit I were more vulnerable to oxidation than those in Unit Summary The existence of numerous cracks in steam generator tubes that had nearly reached through-wall depth indicated continued degradation of these tubes in regions that can be correlated to denting. Based on the analysis of hideout return and the oxide sludge, the conditions for denting and acidic sulfate attack continued to exist in all steam generators. The licensee was giving increased attention to the design and operation of the components of the secondary water system and progress had been made during the past year in preventing condenser leaks. Other actions that are planned include: " tightening" the main condensers; replacing the water treatment plant; replacing the copper alloy feedwater heater tubes; and improving the capacity for blowdown recovery and, thus, reduce condensate makeup. Most of these actions are not scheduled until the next refueling outage In the interim, steam generator degradation is considered likely to continue or accelerate unless the conditions that produce denting and corrosive attack of alloy 600 are eliminate The licensee's procedures for soaking and blowing down hideout return were considered a positive step in this direction. In addition, the licensee had initiated an upgraded water chemistry control program, as discussed belo Implementation of the Licensee's Water Chemistry Program The primary responsibility for controlling water chemistry at the two North Anna units remained divided between the Operations Department (operation of all water treatment and demineralizer systems) and the Chemistry Group. The inspector was informed that in addition to

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problems with the flash evaporators in the water treatment plant, the ,

Water Treatment Group of the Operations Department continued to use a significant amount of resources in maintenance of the condensate polishers and in training operators in the precoating and backwashing of the polishers. The Water Treatment Group was also responsible for the design changes that had enabled part of the blowdown from Unit 2 to be purified and reuse l The inspector identified several significant changes in the operation of the Chemistry Group since the previous inspection. The former supervisor had been transferred to a newly organized technical support group in the licensee's general offices, and a new supervisor had been selected from the Chemistry Group at the Surry Nuclear Plan The secondary water chemistry procedures had been revised to incorporate the recommendations of the SG0G/EPRI guidelines. A steam generator protection agreement with Westinghouse was being initiated in the following manner: new inline instrumentation and sampling lines were being installed in Unit 1 and the panel for similar instrumentation in Unit 2 had been received; plans had been completed for the temporary (about 30 days) installation of an inline ion chromatograph in Unit 1; and a representative of the Westinghouse chemistry staff had been assigned as consultant and coordinator with the Chemistry' Group. The Chemistry Group was routinely using ion chromatography to monitor for

. condenser inleakage and to determine sulfate in steam generator blowdown. Even though the presence of boric acid in blowdown samples complicates the correlation of conductivity and concentrations of anions, the Chemistry Group is using the enhanced sensitivity of ion chromatography to perform these ccmparison (The licensee had established that boric acid is carried over with steam and affects the conductivity of the feedwater).

In addition to the replacement of the Chemistry Supervisor, the Chemistry Group had lost several experienced technicians during the past year, and was operating five shifts with a staff that consisted of a supervisor, and assistant supervisor, one senior technician, three technicians, seven trainees, and one associate. (The inspector was informed that six additional technicians were to be hired). The licensee now has two technicians on each back shift and covers chemistry responsibilities 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day, seven days a week. The licensee agreed that an expedited training program must be implemented to develop experienced technicians who are able to control the stringent chemistry program that has been committed to in the past yea As part of the new control program, the licensee has formalized operational instructions and procedures to maximize the protection given to the steam generators. As mentioned earlier, " chemistry holds" in power ascension during startup had been established at 5% and 30% power to insure that feedwater pumped from the hotwell and feedwater drain tanks have been purified by the condensate polisher Operating procedures also provide for " chemistry holds" during cooldown

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as long .as hideout return continues to increase so that removal of soluble corrosive ions through blowdown can be optimize Summary -

The inspector found the licensee's secondary water chemistry program to be consistent with the commitments given in the response to Generic Letter 85-02 and to contain all the elements required to provide control of the secondary coolant as well as to monitor ingress of impurities. An intensive effort will be required to train the new members of the Chemistry Group while performing the required duties during plant operation and while implementing the new inline instrumentation program. The inspector discussed these demands with members of Plant Management and emphasized the need for future management involvement to assure that the maximum protection of the integrity of the primary coolant pressure boundary is provided by plant design and chemistry contro The inspector also audited the results of analyses performed on the primary coolant and established that all non-radiochemical technical specifications had been me No violations or deviations were identified during this inspection.

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