IR 05000250/1986003
| ML17342A449 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 03/12/1986 |
| From: | Ross W, Stoddart P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17342A448 | List: |
| References | |
| 50-250-86-03, 50-250-86-3, 50-251-86-03, 50-251-86-3, NUDOCS 8604160259 | |
| Download: ML17342A449 (17) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 ma 04
>s86 Report Nos.:
50-250/86-03 and 50-251/86-03 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-250 and 50-251 Facility Name:
Turkey Point 3 and
License Nos.:
, Inspection Condu d:
February 3-7, 1986 c'nspector:
W. J.
Ro Approved by P.
G. Stoddart, Acting Section Chief Division of Radiation Safety and Safeguards SUMMARY-Date Signed Date Signed t
Scope:
This routine, unannounced inspection entailed 40 inspector -hours at the site during normal duty hours, in the area of plant chemistry.
,'esults:
No violations or deviations were identified.
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REPORT DETAILS Persons Contacted Licensee Employees C. J.
Baker, Plant Manager-Nuclear
"K. L. Jones, Acting Plant Manager - Nuclear
"E.
R. LaPierre, Chemistry Department Supervisor D.
E.
Meils, Laboratory Supervisor/Nuclear Chemi stry J.
S.
Seager, Water Treatment Systems Supervisor J.
Wade, Chemistry Training Specialist
"H. E. Hartman, Inservice Inspection Coordinator
- B. A. Abrishami, Inservice Inspection Supervisor Other licensee employees contacted included chemistry technicians.
NRC Resident, Inspectors T. Peebles D. Brewer
- Attended exit interview Exit Interview The inspection scope and findings were summarized on February 7,
1986, with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and summarized 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 the inspector during this inspection.
Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspection.
Unresolved Items Unresolved Items were not identified during the inspection.
Plant Chemistry (79701 and 79502)
As a result of its continuing concern for steam generator tube integrity, the NRC staff has recently i ssued recommended actions and review guidelines that are 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 (SMCP)
to minimize steam generator tube degradation.
The specific plant program should incorporate the secondary water chemistry guidelines in the Steam Generator Owners Group (SGOG)
and Electric Power Research Institute (EPRI)
Special Report EPRI-NP-2704,
"PWR Secondary Mater Chemistry Guidelines," October 1982, and should address measures taken to minimize steam generator corrosion, including materials selection, chemistry limits, and control methods.
In addition, the specific plan 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 chemi stry, as necessary.
The reference guidelines were prepared by the Steam Generator Owners Group Mater 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 exposure.
The objectives of these new procedures were also the objectives of previous inspections (i.e.,
Inspection Report Nos.
50-250, 251/84-06 and 50-250, 251/85-03 dated March 8, 1984, and February 15, 1985).
Prior to the first inspection, the licensee had completed extensive modifications of the secondary water cycle to enhance protection of the steam generators against degradation.
By installing titanium tubes in the main condenser the licensee attempted to eliminate inleakage of the highly saline condenser cooling water into the hotwell and condensate.
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However, condenser tube leaks were still occurring as the result of mechanical damage.
By eliminating copper alloys from the condenser and feedwater heaters, the transport of copper to the steam generators had been stopped and therefore, the corrosive effect of copper on the Inconel 600 steam generator tubes had ceased.
In addition, the installation of a new condensate cleanup system (filter/demineralizers)
increased the licensee's capability to supply water to the steam generators that met the purity criteria recommended by the SGOG and the EPRI.
The licensee had a policy, however, of using these condensate
polishers to expedite cleanup of the condensate/feedwater train during plant startups and then taking them out of service.
As the result, feedwater as well as condensate had become contaminated whenever there had been a
condenser tube leak.
Even with these transients, the integrity of the steam generator tubes appeared, during the last inspection, not to have been degraded, and relatively little iron oxide sludge had been transferred to the steam generators.
The operational experience of the major components of the secondary system was re-assessed during the current inspection (Section (a) below).
After the steam generator tubes had been replaced, the licensee changed its secondary water chemi stry control from phosphate chemistry to the use of all-volatile-treatment (AVT).
Also the licensee endorsed the SGOG/EPRI guidelines and began revising the water chemistry program accordingly.
Although both of these actions were considered to be positive steps toward controlling corrosion in the secondary water system, the licensee's resources ( staff and physical facilities) were considered to be inadequate for implementing the stringent control recommended by the SGOG/EPRI guidelines.
Consequently, these perceived deficiencies were also re-assessed during this current inspection (Section (b) below).
(a)
Plant Design and Operational Experience During this inspection period Unit 3 was operating at full power in its tenth fuel cycle that began in July 1985, and which was scheduled to terminate in January 1987.
Unit 4 was in a refueling outage after its tenth fuel cycle, which commenced in May 1984.
The licensee had considerable difficulty maintaining secondary and primary chemistry control of Unit 3 in the current fuel cycle.
In August 1985, these difficulties had been attributed to start up and power changes which resulted in osci llations in the cation conductivity of the steam generator water as the result of "hideout" and
"hideout return."
In September the concentration of dissolved oxygen had exceeded the SGOG limit (10ppb)
most of the month because of air inleakage through the turbine-condenser
"boot, seal."
This condition had worsened in October until the unit was shut down and the boot replaced.
In October the dissolved oxygen content of the primary coolant had been high because of low overpressure of hydrogen gas in the Chemical and Volume Control System (CVCS) tank.
Finally, in December 1985, another condenser leak caused by mechanical damage to a
tube had been experienced.
The water in the hotwell of Unit 3 had been seriously contaminated in July 1985, by the rupture of an oil line in the turbine.
The inspector was informed that this contamination had been restricted to the hotwell and did not foul the condensate cleanup demineralizers.
During this period the product of the makeup water treatment plant had been contaminated with sodium during the regeneration of'he deep-bed deminerali zer s that were used to purify water for storage in the Demineralized Water Storage Tank (DWST).
An audit of the performance data for Unit 4 since the last inspection showed that during the last six months of the fuel cycle air inleakage had been relatively high (>20 standard cubic feet per minute)
and the dissolved oxygen concentration of the condensate had ranged from 10 to
ppb.
This inleakage had been through the turbine-condenser
"boot" as well as through the seals of the condensate pumps.
Other than during plant perturbations the purity of the steam generator water had remained high (i.e., cation conductivity of - 0.3 umho/cm) thereby indicating essentially no inleakage of condenser cooling water or contaminant ingress through the condensate makeup.
The inspector was informed that during the last refueling outage for Unit 3 (March-July 1985)
the demineralizer tanks in the water treatment plant had been refurbished to remove the "crud" that had been reducing the effectiveness of the ion-exchange resin beds.
(While this cleanup action was in progress makeup water was produced by a mobile water plant that was brought on site.)
The licensee was also considering installing an electrodialysis unit in the water treatment plant to replace the lime pre-treatment process that tended to clog pipes and valves with calcium salts.
Finally, an analysis of the product water by Westinghouse and EPRE had showed that only very low concentrations of organic material were present.
The licensee continued to experience difficulty maintaining the level of dissolved oxygen in the DWST and in the Condensate Storage Tank (CST)
below
ppm.
This condition existed even though the following means were used to prevent air being dissolved in the water in these tanks:
the air vent contained a water seal; both DWST and the CST had nitrogen blankets (although this capability was not in use for the CST);
and the DWST was equipped with a degassifier and the water in the tank could be recirculated.
The high dissolved oxygen levels remained a concern because the two units had several shutdowns during the past year and water from the DWST was used to feed the startup pumps and the steam generators during each plant startup.
The licensee continued to take the condensate polishers out of use as soon as the cation conductivity of the feedwater could be reduced to - 0.3 umho/cm during startup.
As soon as the filter/demineralizers were bypassed, additional ammonia
was injected to raise the pH of the feedwater to 9.6 to reduce corrosion of carbon steel pipes.
When bypassed, the filter demineralizers were backwashed and placed in standby without being precoated.
The inspector was informed that approximately
minutes would be needed to place the first filter/demineralizer back in service.
This policy was not considered to be consistent with the SGOG's recommendations to minimize any
"insult" to the steam generators that might result from ingress of corrosive species such as high concentrations of chloride.
Near the end of the last fuel cycle for Unit 4 the licensee began to cycle steam generator blowdown to the hotwell rather than to waste.
The increased level of soluble and insoluble impurities thus formed in the hotwell and condensate water was compensated for by using one of the filter/demineralizer cells as a
"kidney loop;" i.e.,
approximately 2000 gpm of condensate (-
10% of total flow) is cycled through this filter/demineralizer and back to the hotwell.
The inspector was informed that the effectiveness of this
"kidney loop" will be further evaluated during the next fuel cycle.
The licensee continued to minimize transport of iron oxide to the steam generators by cleaning up the condensate/feedwater train before and during startup.
A "chemistry hold" on power ascension would be imposed before the power level exceeds
percent to ensure that the feedwater met a specified level of purity.
Similarly, the high pressure steam and drain components would be flushed before the feedwater heater drains were pumped forward, and another
"chemistry hold" would be imposed before the power level exceeded 30 percent.
In an effort to minimize the formation of iron oxide the moisture separators were being retubed with more resistant stainless steel tubes.
~Summar During the most recent refueling outages of both Units
and 4 eddy current tests of the steam generator tubes indicated that these tubes remained in good condition.
Likewise, the small amount of iron oxide sludge that was found in the steam generators showed that the startup cleanup procedures had been effective.
The integrity of the secondary coolant system remained vulnerable to degradation as long as both air and condenser cooling water inleakage continued at the rate/frequency observed during the past year.
Control of secondary wate~ chemistry (i.e.,
hideout and hideout return)
would also benefit from improved stability of plant operatio ~
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b.
Water Chemistry Program Program Since the inspector's last site visit the licensee had issued a corporate position on secondary water chemistry (Nuclear Plant Chemistry Parameters Manual, PNS-Chem 1.2, dated January 30, 1985) that was based on the SGOG guidelines.
Subsequently, plant procedures had been revised to incorporate this guidance.
The inspector reviewed Operating Procedure 1560, Secondary Chemistry Control and Limits (dated May 1, 1985)
and verified this procedure now reflected the SGOG limits and action statements for controlling key chemistry parameters during all phases of layup, startup, and plant operation.
These criteria were referenced in Operating Procedure 1568. 1, Secondary Chemistry-Operator Actions in the Event of Deviation from Limits, as goals for minimizing degradation of the steam generator tubes during and following abnormal chemistry events.
Because the condensate poli shers were normally bypassed and not precoated when the plant was operating, Procedure 1568. 1 was directed towards
~recover from an abnormal situation, even when the cation conductivity of the steam generator water might exceed 700 umhos/cm as the result of a condenser tube rupture (Section 5.2 of Procedure 1568. 1). It is the NRC staff's position (Branch Technical Position MTEB 5-3 and Regulatory Guide 1.56) that all possible precautions should be taken to revent or minimize contamination of the feedwater and steam generator water by effective use of a
condensate cleanup system.
The SGOG guidelines are-consistent with the NRC staff's position that even relatively small amounts of corrosive ions (i.e., cation conductivity of
<7 umhos/cm)
may cause both short-term or long-term damage to the steam generator and are cause for prompt shutdown of an operating unit.-
Abnormal chemistry events could be reduced in both intensity and in time if the condensate polishers were available at the start of the event; i.e.,
as soon as a
condenser tube leak is identified.
(2)
Staff Since the last site visit by the inspector the licensee had taken several steps to upgrade its capability of implementing the new control and diagnostic program.
One of these actions was the appointment of a
new Nuclear Chemistry Department Supervisor/Radiochemist.
This individual holds a
B.S.
in Chemical Engineering and formerly had been the Plant Radiochemist.
Responsibilities have been further subdivided among four supervisors who had academic degrees (one in chemistry)
as well as several years of nuclear chemistry
P
8, experience.
These people supervised the activities of 16 technicians, most of whom had a
degree in a
science-related field and/or several years of nuclear chemistry experience.
An extensive onsite program was being developed for training and retraining the members of the Nuclear Chemistry Department in the theories and techniques related to recommendations of the SGOG.
Physical Facilities For the third year in a row the inspector observed that the work of the Nuclear Chemistry Department was being performed under conditions that were not conducive to the type of control program recommended by the SGOG.
Major plant design modifications were still being performed in and around the chemistry laboratory with an attendant environment of dust, noise, and work traffic.
Although the licensee had acquired state-of-the-art analytical instrumentation, the required
"clean-room" environment for the measurement of the trace levels of chemistry variables was not available.
The inspector was informed that better facilities were under study and had been budgeted for; however, no date for the availability of these facilities could be given.
The need for improved facilities for sampling key locations of the secondary water system was again emphasized.
Reliance on grab samples from taps on the open mezzanine deck of the Turbine Building was not considered conducive to the stringent control that has been endorsed in the updated secondary chemistry program.
Instrumentation and guality Control As the allowable limits of potential corrosive species have been reduced to the low part-per-billion (ppb)'ange, the methods for determining these species have also changed.
The inspector observed that several technicians were qualified on the state-of-the-art analytical instruments that had been acquired for trace chemical analyses.
The inspector was informed that formal contracts had been let for maintaining these instruments.
During this inspection all of the major instruments were operable.
With more reliance being placed on instrumental analyses, the licensee has developed a
quality control program that provided continuous assurance that the instruments are calibrated and the technicians were using them correctly.
The inspector reviewed the licensee's program of maintaining control of analytical results through use of replicate samples, intralaboratory
"spiked" samples,
"unknowns" obtained from a contractor, and intralaboratory comparisons
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with other laboratories within the Florida Power and Light Company.
~Summar The licensee has taken several positive actions within the last year to improve its capability to control secondary water chemistry.
It was evident that the Supervisor and staff of the Nuclear Chemistry Department were placing greater emphasis on understanding current corrosion problems and the technology that had been used as bases for the technical guidelines recommended by the SGOG.
The licensee's use of the condensate cleanup system was not providing the control feedwater that was needed as long as condenser tube leaks were being experienced.
Finally, the resources.
needed
- to implement the philosophical as well as technical recommendations of the SGOG require si'gnificantly more management involvement (e.g., training opportunities for supervisors and improvement of physical facilities).