IR 05000338/1987017
| ML20216C389 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 06/22/1987 |
| From: | Hughey C, Kahle J, Ross W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20216C321 | List: |
| References | |
| 50-338-87-17, 50-339-87-17, IEIN-86-106, IEIN-86-108, NUDOCS 8706300275 | |
| Download: ML20216C389 (9) | |
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UNITED STATES
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NUCLEAR REQULATORY COMMISSION
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101 MARIETTA STREET, N.W., SUITE 2900 I
ATLANTA, GEORGIA 30323
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Report ~Nos.: '50-338/87-17 and 50-339/87-17 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 Conducted
- June 8-12, 1987 Inspectors:
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Date 'Sigried Approved by:
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/ Kahle, Section Chief DatY Sighed; Di sion of Reactor Safety-SUMMARY Scope:
This routine, unannounced inspection was conducted in the areas of L
. plant chemistry.
Results: No violations or deviations were identified, i
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l REPORT DETAILS 1.
Persons Contacted
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i Licensee Employees E. W. Harrell,' Station Manager
- M. L. Bowling, Assistant Station Manager
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R. Enfinger, Superintendent of. Operations
- J. A. Stall, Superintendent of Technical Services
- L. G. Miller, Supervisor Chemistry J. Adams, Project Engineer, Service Water System Improvement L. Hartz, Supervisor, Inservice Inspection P. Hensley, Supervisor, Water Treatment
.M. Kansler, Superintendent of. Maintenance J. W. Ogren, Director Operations and Maintenance Support E. R. Smith, Steam Generator Specialist, Operations and Maintenance Support
.0ther licensee employees contacted included chemistry technicians.
NRC Resident Inspectors L. King
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- Attended exit. interview 2.
Exit Interview The ' inspection scope and findings were summarized on June 12, 1987, 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 licensee. The licensee did not identify as proprietary any of the materials provided to or reviewed by i
the inspector during this inspection.
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Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspection.
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Plant Chemistry (79701)
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This inspection was the fourth in a series of assessments of the licensee's capability to maintain the integrity of the primary coolant
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pressure boundary - specifically the integrity of the steam generator j
tubes. As noted in the last inspection report concerning this subject, J
the continuing formation of cracks in these tubes in both units indicated that degradation was occurring through mechanical erosion and several corrosion mechanisms. Eddy current tests of steam generator tubes during
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the current refueling outage of Unit i revealed additional indications of defects in tubes at the top of the tube sheets, at the levels of tube support plates, and in the U-bend regions.
In an effort to eliminate a small primary to secondary leak and to prevent failure of other degraded
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tubes, 118 tubes had been. plugged in the three steam generators. The
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total number of tubes now plugged represents 6.17 percent, 5.25 percent, and 7.99 percent of all tubes in Steam Generators A, B, and C of this unit.
All three steam generators of Unit I were also sludge lanced during the current outage, and a total of 3500 pounds of metal oxides (iron and i
copper) had been removed.
i Through an audit of chemistry data and discussions with cognizant personnel from the plant and corporate staffs, the inspectors established that the licensee was addressing deterioration of steam generator-tubes and wastage of carbon steel components of the steam and power conversion
system (i.e., the secondary water system) in a number of ways; e.g.,
' tightening', repairing, or replacing individual components, expanding inservice surveillance programs, and upgrading chemistry diagnostic and control capabilities. These actions are summarized below, and each action has been evaluated as to its potential for mitigating ongoing tube and pipe degradation as well enhancing long-term protection against deterioration from corrosion mechanisms, a.
Plant Design and Operation
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The inspectors reviewed the effectiveness of each of the principal
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components of the secondary water systems relative to either j
prevention of ingress or removal of contaminants that could cause
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corrosion of the steam generator tubes.
(1) Main Condenser - Through an audit of chemistry data taken during i
1987 the inspectors observed that the quality of water in the condenser hotwells had been maintained at high levels in both units; e.g., cation conductivity 0.10-0.12 umhos/cm, specific j
conductivity 3 to 5 umhos/cm, sodium at non-detectable levels, and dissolved oxygen 3 to 8 ppb. (conductivity measurements of samples from the hotwell and steam generator blowdown were considered to be biased on the high side because of the presene i
of boric acid that was being continuously added to the steam generator water to control denting of steam generator tubes.)
Water inleakage through the condenser had been essentially eliminated, as indicated by the sodium content of the hotwell water, since che last inspection in March 1986.
This was achieved by throttling down the flow of condenser cooling water during colder months so that the differential temperature in the condenser was maintained at approximately 15F.
This action prevented vibration of the condenser tubes, with accompanying leaks at tube-tube sheet interfaces, as had occurred in previous
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winter. seasons when-the vaceum within.the condenser increased
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. because of - higher level 5.-of' AT.
Air inleakage through the j
- multitude of-components -associated with evacuated systems had
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been 66, SCFM-in Unit 2 but somewhat highe r, 10-16. SCFM, in:
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Nnit I due'to small leaks that had escaped detection.
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As a consequence of their review, the inspectors concluded that-l significant progress had, been.made in eliminating pathways of
. air and soluble contaminants through the. main condenser.
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- (2) SerEice' Water System
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Tic inspectors were informed that ' programs ~' designed to eliminate microbiological induced corrosion (MIC) in various pipe and
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valves associated with the Service Water System w'as still under l
development. Since the inspector's site visit in March 1985 all of the service water lines (safety' and nor.-safety rebted) had been cleaned by hydrolasing to remove organic and inorganic flim
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and corrosion products.
Subsequently, the metal surfacts were.
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treated with-a surfactant' in preparation for'the initiation cf a
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new biocide to ' prevent further attack bv microorgeisms.
(especially iron-fixing and sulfate-reducing bacteria)'and microorganisms such as Asiatic clams.
Whent metal loss was s considered' to be excessive pipe sections had bee'n. cut out and replaced.
The. inspectors were infchned.1.h'at ~ several' largs
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valves had been upgraded with' disks fabricated from gta'ialess steel.
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The inspectors considered that these aStions, alor.9. with an Wgraded ISI program, should provide increatd protection
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y-(3) Water Treatment Plant
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As the result of continuing problems with the original water tredmont plants, especially the flash evaporators, the licensee had thur down these plants for major overhaul. f he licensee had T
contracted for a portable water treatment system to provide demineralized water for condensate makeup and other plant uses
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while the oldtr plants were out of service.
The inspectors reviewed the operation of the portable system through a walkdown of the modular components and discussions with the contract operator and licensee personnel.
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The plant Nonsisted of interchangeable water purification un'its that used both domineralizing (iron exchange resin beds) and reverse osmosis mechanisms to produce water of very high purity (specific conductivity of 0.058 umho) and low oxygen content (2 a
ppb) at a rate of 200 gpm per unit - four units were available on site at all times.
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o Although the original water. treatment plant was being upgraded, the licensee was considering using the reverse osmosis system on a ' permanent basis.
The inspectors considered the reverse osmosis system was satisfactorily providing water of a quality L-
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that minimized ingress of contaminants into the secondary water system.
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( 4') Condensate C1hanup System
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s As ncted in previous inspection reports the inspectors observed
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that the licensee was continuing to experience problems with the
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powdered-resin demineralizers used for condensate cleanup.
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Full-flow polishing had been performed satisfactorily during unit startups but, subsequently, only one of the five beds were retained in tuse - to help control the concentration of ammonia (i.e., to control pH). The principal deficiency associated with the demineralizers continued to be " throw" of chloride ions and resin pdyticles.
More than half of these particles are less i
than 15 microns in size.
In an effort to reduce this type of contamination of the feedwater the licensee was investigating different. types of filter elements and ion-exchange resins.
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Even Uith minimum polishing the licensee had been able to
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maintain high quality feedwater (i.e., cation conductivity of 0.14 to 0.16 umho/cm and no detectable dissolved oxygen). The s
inspectors were not able to assess the extent to which soluble and solid species of copper and iron were being transported into the 'feeovater because of insufficient data.
The usefulness of
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analyses of copper and iron for establishing the extent of general corrosion of low-and high pressure components, and subsequent transport of corrosion products to the steam generators, was discussed with members of the chemistry staff.
Although the licensee had a program to remove all copper-containing components from the secondary coolant system, the inspectors observed that only feedwater heater No. 5 in Unit I had been replaced so far.
(Feedwater heater No. 6 in both units had originally been tubed with stainless steel tubes.) All of the remaining feedwater heaters had copper alloy tubes that are scheduled to be replaced with stainless steel
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tubes during the next two refueling outages for Unit 1 and the next three refueling outages for Unit 2 - a period of 3 to 5
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years. Copper components remain a concerr. because the presence of copper in the sludge of steam generators has been shown to cause the type of tube denting that has been identified in both North Anna units.
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.(5), Assessment
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this area the licensee' was
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>Since the' last ' inspection -in
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considered to have made"significant progress in reducing the ingress of-corrosive' species into the secondary coolant system.
Efforts were continuing to' reduce air inleakage. The condensate c"eanup l systems hai provided effective startup cleanup of the
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- condensate /feedwater cycle and. the high pressure extraction s'.eam and drain lines. - Although the polishers could not be used
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to maintain full-flow polishing during plant - operation, the quality of the feedwater had-been maintained at an acceptable l
level. As will be discussed later, the presence of copper-alloy
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fet.dwater heater ' tubes continued to place constraints on chemistry contral and was considered to be contributing to tube denting in the steam generators.
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_During this phase of the inspection no violation or deviations were j
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identified.
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Chemistry Control
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(1) Primary Chemistry
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~A summary audit of data obtained since the last inspection in i
this area showed that all Technical Specification limits associated with the reactor coolant system had been _ met. The J
inspectors were informed that guidelines recently ' published by
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the Electric Power Research Institute (EPRI) _for minimizing
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i out-of-core radiation levels were being reviewed for possible i
modification of the coordinated lithium-boron procedure for I
controlling pH of the reactor coolant.
(2) Secondary Chemistry k
Control of secondary water chemistry continued to be based on l
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guidelines developed by the Steam Generators Owners Group (SG0G)
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and Westinghouse.
Although protection.of the steam generator
(i.e., the primary coolant pressure boundary) continued to be
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the principal goal, the licensee was aware that prevention of general corrosion and wastage of other components of the secondarv water system must also be considered. This subject will be discussed in greater detail in Paragraph 6 of this j
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report.
y Because of the low level of ingress of contaminants and the effectiveness of startup cleanup procedures the licensee had '
been able to exceed the chemistry criteria recommended by the SGOG; however, very large amounts of metal oxide sludge
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continued to be transported to the steam generators (especially in Unit 1), and relatively large amounts of ionic impurities continued to be identified in steam generator hideout return,
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I The level of hideout return. was a'ttributed to ingress of condenser cooling water and leakage of ion exchange resins from the condensate polisher during earlier fuel cycles. Efforts had
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been continuing to reduce the levels of such ions as chloride, sulfate, sodium, potassium,. calcium, and magnesium by blowdown, especially during. normal shutdowns.
However, the extent of.
which these potentially corrosive ions were being removed from crevices and.other localized environments was uncertain as long as large amounts of sludge were present in the' steam generator.
The cause of continuing wastage of carbon steel pipe in the low-
and.high pressure components of the secondary water system and
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the buildu'p of sludge in the steam generators was considered by the inspectors to be of concern because sludge production in most other PWRs in Region II has been decreasing significantly-since licensees have implemented SGOG control guidelines.
The inspectors reviewed in depth with representatives of 'the licensee the possible causes for sludge buildup.
These
' discussions focused on pH control and the use of boric acid to
control denting of steam generator tubes. As discussed earlier, i
the presence of copper feedwater tubes and the licensee's policy of maintaining a concentration of boric acid.in the steam generator water at 5 to 10 ppm had resulted in the pH of the
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steam generator being approximately 7.5 (at 25C).
However, l
even' though approximately 10. percent of the boric acid may
volatilize.'in steam and be transferred 'to the water in the hotwell, the pH of both condensate and feedwater had remained at 8.6.to 9.0.
This pH range was within the limits recommended by the SG0G as a compromise to minimize corrosion of both copper and
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ferrous materials.
The inspectors discussed with licensee personnel a perceived need to review the current chemistry. control program with the goal of reducing the transport of iron and copper oxide sludge into the steam generator, where, in the presence of known high concentrations of chloride, the denting phenomenon could be supported.
The licensee's representatives agreed that better understanding of sludge formation was needed, but first priority had to be given to the control of existing denting conditions and prevention of extensive tube failure.
c.
Water Chemistry Control Program The inspectors reviewed the current status of the following three elements of tne licensee's chemistry program:
staffing and training quality contrc1 program sampling capabilities
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i In the interval since the last' inspection in this area the
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' chemistry staff had been increased to a total of 22 personnel (plus-two chemistry ' nstructors-in the Plant Training i
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technicians the inspectors reviewed the licensee's program for
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on-the-job and classroom training and the extent to which the i
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newer technicians had been qualified.
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- The inspectors also reviewed control' charts that were being l
maintained for key chemistry variables in the secondary coolant system; and discussed, with the responsible chemistry staff member,; the actions being taken to implement a quality control program.
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The inspectors observed that the inline sampling system that was
being installed as part of the steam generator maintenance
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program with Westinghouse was not yet operable, although the monitoring panels had been installed. These panels were located in the turbine buildings of each unit and will provide continual readout for as many as five chemi stry parameters (sodium, hydrazine, pH, cation conductivity, and dissolved oxygen) from the following locations:
condensate makeup condensate pump discharge heater drains feedwater steam. generator blowdown main steam The inspectors consider that this system will provide sufficient data to permit the chemistry staff to continually monitor most chemistry control parameters.
Chloride, sulfate, and silica will continue to be monitored through the use of grab samples, as will be the effluents of the condensate polishers.
During this part of the inspection no violations or deficiencies were identified.
6.
Review of Licensee's Actions In Response to IEN Notices86-106 and 86-108.
a.
IEN 86-106 Feedwater Line Break The inspectors observed that, because of this licensee's particular concern over the pipe rupture at the Surry Nuclear Plant in December 1986 and the similarity of design of the Surry and North Anna Plants, a comprehensive program had been developed to address the concerns discussed in this Notice.
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The following. actions had ' been taken or. are scheduled - to be performed:
Immediately after the Surry accident' the power levels of the North-Anna ' units had been decreased to facilitate inservice inspection (ISI) test'ng of feedwater -lines.
No indication of.
excessive thinning had been observed.
During the Unit I refueling outage 80 points on single phase fluid lines and 44 points on two phase lines were identified asL potential. sites of errosion/ corrosion thinning.
As the ' result of the ISI inspection of the above 124 points, 101. additional points were. inspected (69 single phase and 32 two. phase)' and 27 pipe sections of feedwater lines,
'high pressure extraction steam' lines, and moisture separators heater'and crossover lines were replaced (some with higher alloy.
material s).
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. Candidates for a similar ISI program for Unit 2 were being
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identified for testing during the up-coming refueling outage for this unit.
'The pre-existing ISI program for two phase systems was being reviewed for completeness.
A corporate level investigation of the role of materials in pipe-i thinning had been initiated.
' The licensee was cooperating in an EPRI effort to develop a computer model for erosion / corrosion loss rate that will. include all of the elements that had been identified in the Notice as possible contributors to the Surry pipe rupture.
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IEN 86-108 Degradation of Reactor Coolant System Pressure Boundary Resulting From Boric Acid Corrosion The inspectors were informed that this Notice had been addressed by performing visual inspections of the reactor coolant system to the greatest extent possible while both units were operating and by reviewing leak-rate measurements at both units. Also, an in-depth i
review of this subject was being performed by designated groups within the Technical Support and Maintenance Departments.
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