ML20127A808
| ML20127A808 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 06/18/1985 |
| From: | Andrews R OMAHA PUBLIC POWER DISTRICT |
| To: | Thompson H Office of Nuclear Reactor Regulation |
| References | |
| GL-85-02, GL-85-2, LIC-85-259, TAC-58060, NUDOCS 8506210266 | |
| Download: ML20127A808 (14) | |
Text
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Omaha Public Power District 1623 Harney Omaha, Nebraska 68102 402/536 4000 June 18, 1985 LIC-85-259 Mr. Hugh L. Thompson, Jr., Director Division of Licensing Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, DC 20555
Reference:
Docket No. 50-285
Dear Mr. Thompson:
Staff Recomended Actions Stemming from NRC Integrated Program for the Resolution of Unresolved Safety Issues Regarding Steam Generator Tube Integrity (Generic Letter 85-02)
The Omaha Public Power District received the subject letter dated April 17, 1985.
Please find enclosed the District's responses to the various inquiries.
The past correspondence between the District and the Nuclear Regulatory Commission listed below should be used as references in evaluating this submittal.
1)
Letter from NRC (J. T. Collins) to OPPD (W. C. Jones) dated (June 5, 1984)
- 2) Letter from 0 PPD (W. C. Jones) to NRC (J. T. Collins) dated June 19, 1984 (LIC-84-196)
- 3) Letter from 0 PPD (R. L. Andrews) to NRC (R. D. Martin) dated February 2,1985 (LIC-85-040)
- 4) LetterfromOPPD(R.L.Andrews)toNRC(J.R. Miller) dated March 1, 1985 (LIC-85-091)
- 5) Letter from NRC (R. P. Denise) to OPPD (R. L. Andrews) dated March 27, 1985 Sin rely, g506@1820D oso ppa R. L. Andrews hob 2(o e
Division Manager p
Nuclear Production RLA/DJM/dao Attachments cc:
LeBoeuf, Lamb, Leiby & MacRae 1333 New Hampshire Avenue, N.W.
W1shington, DC 20036 Mr. E. G. Tourigny, NRC Project Manager Mr. L. A. Yandell, NRC Senior Resident Inspector O
h
- =, -
0 The April 17, 1985 Generic Letter 85-02 requested responses to " Staff i
Recommended Actions Stemming from NRC Integrated Program for the Resolution of Unresolved Safety Issues Regarding Steam Generator Tube Integrity" and
" Request for Infomation Concerning Category C-2 Steam Generator Tube Inspections."
The District's responses are as follows:
1.a PREVENTION AND DETECTION OF LOOSE PARTS (INSPECTIONS)
Staff Recommended Action Visual inspections should be perfomed on the steam generator secondary side in the vicinity of the tubesheet, both along the entire periphery I
of the tube bundle and along the tube lane, for purposes of identifying loose parts or foreign objects on the tubesheet, and external damage to peripheral tubes just above the tubesheet. An appropriate optical de-vice should be used (e.g., mini-TV camera, fiber optics). Loose parts l
or foreign objects which are found should be removed from the steam gen-erators. Tubes observed to have visual damage should be eddy current inspected and plugged if found to be defective.
These visual inspections should be performed:
(1) for all steam gener-ators at each plant at the next planned outage for ed@ current test-ing, (2) after any secondary side modifications, or repairs, to steam l
generator internals, and (3) when eddy current indications are found in the free span portion of peripheral tubes, unless it has been estab-lished that the indication did not result from damage by a loose part or foreign object.
For PWR OL applicants, such inspections should be part of the preser-l vice inspection.
For steam generator models where certain segments of the peripheral re-gion can be shown not to be accessible to an appropriate optical de-vice, licensees and applicants should implement alternative actions to address these inaccessible areas, as appropriate.
Licensees should take appropriate precautions to minimize the potential l
for corrosion while the tube bundle is exposed to air. The presence of l
chemical species such as sulfur may aggravate this potential, and may make exposure to the atmosphere inadvisable until appropriate remedial measures are taken.
3 l
District Response Detailed secondary inspections are conducted during each refueling out-age in both Fort Calhoun steam generators. These inspections involve a detailed crawl-through of the secondary sides of the steam generators
[
to ascertain that components are properly secured and in good condi-tion, sludge and scaling sampling and analysis, inspection of steam gen-erator internals from the handholes, and photographic documentation.
i Any loose parts or foreign objects observed during these inspections are removed from the steam generators.
l l
, - ~ _ _ _,.. - _ _ _ _ _ _.. _ _ _,. _ _.. _ _.. -,,.
During the 1984 refueling outage, CE attempted to perfonn annulus in-spections of both steam generators using a remotely controlled inspec-tion cart. These inspections would also enhance detection and removal of foreign objects from the steam generators.
The District utilizes wet lay-up with hydrazine and make-up from the emergency feedwater storage tank to minimize steam generator corrosion.
The steam generators are exposed to air only when work inside the steam generators will not permit wet lay-up.
1.b PREVENTION AND DETECTION OF LOOSE PARTS (QUALITY ASSURANCE)
Staff Recommended Action Quality assurance / quality control procedures for steam generators should be reviewed and revised as necessary to ensure that an effective system exists to preclude introduction of foreign objects into either the primary or secondary side of the steam generator whenever it is opened (e.g., for maintenance, sludge lancing, repairs, inspection oper-ations, modifications). As a minimum, such procedures should include:
(1) detailed accountability procedures for all tools and equipment used during an operation, (2) appropriate controls on foreign objects such as eye glasses and film badges, (3) cleanliness requirements, and (4) accountability procedures for components and parts removed from the in-ternals of major components (e.g., reassembly of cut and renoved compo-nents).
District Response Standing Order M-10 establishes tool accountability standards for pri-mary and secondary sides of the steam generators when their access ways have been opened. Tool accountability logs are maintained where neces-sary to minimize the possibility of introducing foreign materials into 3
the steam generator. Current procedures require a tool accountant to be assigned to the area when work is in progress. According to M-10, any items such as film badges and eye glasses must be secured by tape or a cord. Any parts or components removed from the steam generators are recorded on the tool accountability log as they exit the steam generators. After work is completed in either the primary or secondary sides of the steam generators, a quality control inspector performs a closeout inspection prior to closing the system to again check for for-eign objects and monitor the general cleanliness of the area.
2.a INSERVICE INSPECTION PROGRAM (FULL LENGTH INSPECTION)
Staff Recommended Action The Standard Technical Specifications (STS) and Regulatory Guide 1.83, Part C.2.f, currently define a U-tube inspection as meaning an inspec-tion of the steam generator tube from the point of entry on the hot-leg side completely around the U-bend to the top support of the cold-leg side. The staff reconmends that tube inspections should include an inspection of the entire length of the tube (tube end to tube end) in-cluding the hot leg side. U-bend, and cold leg side.
a This recommended action does not mean that the hot leg inspection sam-ple and the cold leg inspection sample should necessarily involve the same tubes. That is, it does not preclude making separate entries from the hot and cold leg sides and selecting different tubes on the hot and cold leg sides to meet the minimum sampling requirements for inspec-tion.
Consistent with the current STS requirement, supplemental sample inspec-tions (after the initial 37, sample) under this staff recommended action may be limited to a partial length inspection provided the inspection includes those portions of the tube length where degradation was found during initial sampling.
District Response The District currently perfoms full length (tube end to tube end) in-spections during eddy current examinations of the Fort Calhoun Station steam generators.
2.b INSERVICE INSPECTION PROGRAM (INSPECTION INTERVAL)
Staff Recomended Action The maximum allowable time between eddy current inspections of an indi-vidual steam generator should be limited in a manner consistent with Section 4.4.5.3 of the Standard Technical Specifications, and in addf-tion should not extend beyond 72 months.
District Response Standard Technical Specification (STSs) Section 4.4.5.3 is consistent with Fort Calhoun Technical Specification (FC-TS) 3.3(c) regarding eddy current inspection frequency. These allow regularly scheduled inspec-tions to be limited to one steam generator on a rotating schedule.
Both (STSs and FC-TSs) maintain that if two consecutive inspections result in all inspection results falling into the C-1 category or if two consecutive inspections demonstrate that previously observed degrad-ation has not continued and no additional degradation has occurred, the inspection interval may be extended to a maximum of once per 40 months.
For the two steam generators at Fort Calhoun, this could result in an interval of 80 months between required inspections on an individual steam generator.
Although the Technical Specification allows such an inspection interval, the District has made a commitment to ensure steam generator integrity and this would minimize the possibility of operat-ing for such a period without perfoming appropriate steam generator tube inspections.
3.a SECONDARY WATER CHEMISTRY PROGRAM Staff Recommended Action Licensees and applicants should have a secondary water chemistry pro-gram (SWCP) to minimize steam generator tube degradation.
The specific plant program should incorporate the secondary water chem-istry guidelines in SG0G Special Report EPRI-NP-2704, "PWR Secondary Water Chemistry Guidelines," October 1982, and should address measures taken to minimize steam generator corrosion, including materials selec-tion, chemistry limits, and control methods.
In addition, the specific plant procedures should include progressively more stringent corrective actions for out-of-specification water chemistry conditions. These cor-rective actions should include power reductions and shutdowns, as appro-priate, when excessively corrosive conditions exist.
Specific function-al individuals should be identified as having the responsibility / author-ity to interpret plant water chemistry infonnation and initiate appro-priate plant actions to adjust chemistry, as necessary.
The referenced SG0G guidelines above were prepared by the Steam Genera-tor Owners Group Water Chemistry Guidelines Commhtee and represent a consensus opinion of a significant portion of the industry for state-of-the-art secondary water chemistry control.
District Response In Appendix A, Fort Calhoun secondary water chemistry limits and cor-rective actions are compared to EPRI/SG0G PWR Secondary Water Chemistry Guidelines, Revision 1, June 1984. District management is strongly com-mitted to operating the Fort Calhoun Station with prudent chemistry con-trol.
Secondary chemistry guidelines and operating ifmits, which are consistent with the current recommendations of both Combustion Engineer-ing and Steam Generator Owners Group II, have been fonnally adopted.
Hold points for chemistry during startup have been mandated to ensure optimum chemistry conditions in the generators. These guidelines and limits include corrective action levels, shutdown levels, and the ac-tions necessary to return chemistry parameters to wit *.in specifica-tions.
The present low pressure feedwater heaters at Fort Calhoun Station are equipped with copper alloy tubes. The District has purchased replace-ment stainless steel tube bundles, which will be installed during the 1985 refueling outage. This will reduce the further deposition of cop-per and copper oxides in the steam generators and will allow operating chemistry paramters to be adjusted to provide optimal corrosion con-trol.
3.b CONDENSER INSERVICE INSPECTION PROGRAM Staff Recommended Action Licensees should impicment a condenser inservice inspection progran.
The program should be defined in plant specific safety-related proco-dures and include:
1.
Procedures to implement a condenser inservice inspection progran that will be initiated if condenser leakage is of such a magni-tude that a power reduction corrective action is required more than once per three month period; 2.
Identification and location of leakage source (s), either water or air; 3.
Methods of repair of leakage;
4.
Methodology for detenntning the cause(s) of leakage; and 5.
A preventive maintenance program.
District Response The District is committed to prompt and prudent corrective action in the event that secondary chemistry operating limits, including those relating to condenser inleakage, are exceeded. The chemistry operating limits are outlined in Appendix A.
As an example of this commitment, prompt investigative action was taken during December when an increase in the dissolved oxygen content in the condensate was noted. This problem was traced to air inleakage at a condensate pump. The pump was removed from service and corrective maintenance was performed. The dissolved oxygen content was brought back within specifications within the action level time frame specified in the chemistry procedures.
Air inleakage is identified by measuring oxygen at the condensate pump di scharge.
Excessive air inleakage is also found by readings of the rotometers which measure condenser of f gas flow at the condenser evacua-tion pumps. Leaks can then be located by using helium at a tracer gas.
Water inleakage during operation is first detected by using sodium anal-yzers and cation conductivity meters installed on the blowdown. To find the exact location of the leak, the plant is brought down to half load.
This is done so that one of the condensers can be taken out of service at a time, but a vacuum is still maintained. Then helium is introduced into the condenser waterbox which is out of service and the mass spectrometer analyzes the offgas for any trace of the helium.
The other method utilized to locate water inleakage is practiced just prior to startup, af ter an extended outage. This method involves flooding the shellside of the condenser with water and fluorescent dye, Blacklights are then used to locate any fluorescent dye which may have leaked through a tube or tube to tubesheet joint.
Repairs made for air inleakage problems will usually differ with each situation.
In some cases the repair may call for a replacement of seals in either valves, pumps or condenser joints.
In other cases, the problem may be operational, i.e., a valve left open, too low of a level in the gland steam condenser, etc.
Air inleakage causes are determined on a case by case basis.
For water inleakage, tubes are plugged on both ends with a rubber stopper which has a bolt in it. Tightening down on the bolt causes the stopper to expand and effectively seal off the tube. Tube to tubosheet joints are re-rolled if found to be leaking.
To aid in detennining the cause(s) of water inleakage, a metallurgical analysis will be porformed on three tubes during the fall refueling outage. The three tubes will be identified as "known" toiled tubes, then the tubes will be pulled and sent off for analysis. The analysis i
L
I' should help to determine the failure mechanism (s) present in the conden-ser environment and enable corrective actions to be developed, if neces-sary. Eddy current testing, also to be perfomed during the upcoming outage, will also provide insight as to the possible failure mechan-ism (s) by identifying affected areas, pitting, tube wear and other pos-sible agents.
For preventive maintenance, annual checks are made for air inleakage l
with the helium gas method. This frequency may be increased if a l
problem arises.
The condenser tubes are cleaned every extended outage, otherwise the circulating water flow is maintained in order to eliminate stagnant flow conditions which would enhance a corrosive enviroment. Al so,
eddy current testing will be performed on 10 to 207, of the tubes during the 1985 refueling outage. Similar inspections may be perfomed during l
future outages depending on the results of this inspection.
l 4.
PRIMARY-TO-SECONDARY LEAXAGE LIMIT I
Staff Recommended Action l
All PWRs that have Technical Specification limits for primary-to-second-l ary leakage rates which are less restrictive than the Standard Techni-cal Specifications (STS) limits should implement the STS limits.
l District Response l
l Standard Technical Specification Section 3.4.6.2 is consistent with Fort Calhoun Station Technical Specification Section 2.1.4 in that pri-mary-to-secondary leakage through the steam generator tubes shall be limited to 1 gpm total for both steam generators. Following the tube rupture event of May 16, 1984, Special Order No. 35 entitled, " Allow-able Primary-to-Secondary Reactor Coolant System Leak Rate" was issued to establish an interim primary-to-secondary leakage limit through the steam generator tubes of 0.3 gpm total for both steam generators.
5.
COOLANT IODINE ACTIVITY LIMIT Staff Recommended Action FWRs that have Technical Specification limits and surveillance for cool-ant iodine activity that are less restrictive than the Standard Techni-cal Specification (STS) should implement the STS limits. Those plants identified above that also have 104 head high pressure safety injection pumps should either:
(1) implement iodine Ifmits which are 20L of the STS values, or (2) impicment reactor coolant pump trip criteria which will ensure that if of fsite power is retained, no loss of forced reac-tor coolant system flow will occur for steam generator tube rupture l
events up to anti including the design basis double-ended break of a sin-gle steam generator tube, and implement iodine limits consistent with the STS.
I
District Response Fort Calhoun Station has low head high pressure safety injection pumps.
In Fort Calhoun Emergency Procedure EP-30 " Steam Generator Tube Leak /
Rupture," immediate action to be taken following such an event includes tripping two of the four reactor coolant pumps (one in each loop).
This would ensure that no loss of forced reactor coolant systen flow would occur. According to the Fort Calhoun Station Updated Safety Analysis Report Section 14.14, steam generator tube rupture incident analysis considers a double-ended break of a single steam generator tube.
Standard Technical Specification Section 3.4.8 states that the specific activity of the primary coolant shall be limited to < 1.0 uCi/gran Dose Equivalent I-131 and < 100/E uCi/ gram total non-iodilie activity.
These limits are consistent with Fort Calhoun Technical Specification Section 2.1.3.
6.
SAFETY Ill1ECTION SIGNAL RESET Staff Recommended Action The control logic associated with the safety injection pump suction flow path should be reviewed and modified as necessary, by ifcensees, to minimize the loss of safety function associated with safety injec-tion reset during an SGTR event. Automatic switchover of safety injec-tion pump suction from the boric acid storage tanks (BAST) to the re-fueling water storage tanks should be evaluated with respect to whether the switchover should be made on the basis of low BAST level alone with-out consideration of the condition of the SI signal.
Of strict Response At the Fort Calhoun Station, safety injection pumps take suction from the safety injection and refueling water tank. The switchover of safe-ty injection pump suction from the boric acid storage tanks to the re-fueling water storage tanks, therefore, does not apply to Fort Calhoun Station operation.
7.
REQUEST FOR INFORMATION CONCERNING CATEGORY C-2 STEAM GENERATOR TUBE INSPECTIONS Information Requested The enclosed draf t NUREG-0844 Section 2.2.1.2 describes certain Ifmita-tions which the staff believes to be inherent in the present Tc;hnical Specification steam generator IS! requirements pertaining to Category C 2 inspection results. Licensees and applicants are requested to pro-vide a description of their current policy and actions relative to this issue and any recommendations they have concerning how existing Techni-cal Specification steam generator ISI requirements pertaining to Cate-gory C-2 inspection results could be improved to better ensure that ade-quate inspections will be perfomed. This description should include a response to the following questions:
1.
What factors do, or would, the Itcensee or applicant consider in determining (a) whether additional tubes should be inspected be-yond what is required by the Technical Specifications, (b) whe-ther all steam generators should be included in the inspection program, and (c) when the steam generators should be reinspected?
2.
To what extent do these factors include consideration of the de-gradation mechanism itself and its potential for causing a tube to be vulnerable to rupture during severe transients or postu-lated accident before rupture or leakage of that tube occurs dur-ing normal operation?
District Response Fort Calhoun Technical Specification 3.3(2) describes the surveillance program for the steam generator tubes.
This defines in-service inspec-tion as being perfomed on each steam generator on a rotating schedule encompassing a minimum of 300 tubes of the total 5,005 tubes per steam generator. Table 3-8 outlines when additional tubes should be inspect-ed and whether both steam generators should be included in the inspec-tion program.
Section C describes inspection frequencies.
While a 300 tube random sample is a reasonable proven starting point for eddy current inspection of a steam generator, the District frequent-ly elects to examine more than the required minimum number of tubes.
Depending on the nature and location of the indications obtained during the initial inspection, the scope of the exam could be expanded to better survey the areas of interest. This allows for a more accurate assessment of the condition of the steam generators.
The original inservice inspection plan for 1984 encompassed 1,454 tubes in steam generator "A" and 1,034 tubes in steam generator "E".
The inspection was later expanded to encompass all accessible tubes in both steam generators "A" and "B" per letter from NRC (J. T. Coliins) to OPPD (W. C. Jones) dated June 5,1984.
The scheduled inspncion for 1985 includes approximately 500 tubes in each steam generawr. The inspection pattern will be concentrated in spect fic areas where various indications have been detected during past inspections. The pattern will also include examination of those tubes with nonpluggable indica-
~
tions and a selection of tubes which will reveal if any of the types of problems which have been noted in other Combustion Engineering steam generators are present at Fort Calhoun.
In the event that the results of the inspections show that the scope should be expanded, additional inspections will be conducted. The Olstrict believes that such an examination program will provide an accurate assessment of the condi-tion of the Fort Calhoun steam generatnrs and will provide adequate assurance of prolonged operational integrity.
Appendix A EPRI/0 PPD SECONDARY SIDE CHEMISTRY PROGRAM COMPARISON l
Blowdown
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
t pH 8.5 - 9.0 None None 8.5 - 9.2 None None Comment:
The District has adopted the CE limits as shown in Action Level 1).
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
Cation Con.
<0.8
>2
>7 None None None l
l ductivity l
umho/cm i
Comment:
OPPD installed on-line analyzers on blowdown for cation conductivity this spring. Limits for cation conductivity have been developed and I
are presently being approved by the plant staff. These closely ap-j proximate the suggested EPRI limits.
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
i Sodium ppb
<20
>100
>500
<20, 20-50***
<100 500 l
- Increase blowdown if 20 <[ sodium ppb) <50.
If >50, initiate II.A.
Comment:
On-line analyzers are installed, and operating on blowdown. Appropri-ate grab samples can be run, and will be run more frequently if all sodium and cation conductivity on-line analyzers are out of service.
Action levels for sodium have been adopted to cover increased blow-l down, power reduction and imediate shutdown.
l
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
Chloride ppb
<20 100 None
<20 f100 None Comment:
The OPPD limits are the same as the EPRI limits.
l l
\\
- See " Secondary System Corrective Action" section. Definitions of 1, 2 and 3 l
are II. A.1, II. A.2 and II. A.3 for all parameters.
i
- See EPRI/SG0G _PWR Secondary Water Chemistry Guidelines, Revision 1 June 1984 l
for EPRI Action Level Dertnf tions or 1, z and 3.
l l
l l
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
Sulfate ppb
<20 None None
<100
<200 None Comment:
An ion chromatograph is now in service for grab samples.
The Dis-trict will develop a baseline for normal operation, startup, and shutdown before adopting lower limits and 6ction levels.
- Action Level and Limit
- Action Level and Limit Parameter M EPRI 2J 3J ll0 PPD g
3J Silica ppb
<300 None None
<300 None None Comment:
The OPPD limits are the same as the EPRI limits.
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
pH 8.8 - 9.2 None None 8.8 - 9.2 None None Comment:
The OPPD limits are the same as the EPRI limits.
l
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
0xygen, ppb
<5 None None
<5
<20 Hone Comment:
The OPPD Ifmits are the same as, or more conservative than, the EPRI l
limits.
- Action Level and Limit
- Action Level and Limit l
Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
Iron, ppb
<20 None None
<20 None None Comment:
The OPPD limits are the same as the EPRI limits.
- Action Level and Limit
- Action Level and Limit Parameter
Copper, ppb
<2 None None
<2 None Hone Comment:
The OPPD limits are the same as the EPRI Ilmits.
,e
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
Hydrazine,
>20 None None 10 - 50 50 - 100 None ppb Comment:
The District has adopted these limits to allow for adjustment of the hydrazine based on our operational experience, so that oxygen and pH can be controlled seasonally. The District has adopted the Combus-tion Engineering limit.
Condensate
- Action Level and Limit
- Action Level and Limit Parameter
- 1) EPRI 2) 3)
- 1) OPPD 2) 3)
,,30 None Oxygen, ppb
<10
>30 None
<10 Comment:
The OPPD limits are the same as, or more conservative then, the EPRI limits.
AUTHORITY OF OPERATING MANUAL The Operating Manual prescribes the policies, procedures, and instructions to safely operate the Fort Calhoun Station Unit No.1. Adherence to the Operating Manual is mandatory per Fort Calhoun Station Standing Order G-7.
The Chemistry Manual is part of the station Operating Manual. The following is extracted from the Operating Manual Procedure CMP-5, Rev.1, currently in of fect and governing operations.
I.
PRINCIPLES OF CORRECTIVE ACTION Certain steps are mandatory in the resolution of ary chemical systen ab-normality or out-of-specification result. They are:
A.
Resample and reanalyze. Correct sampling procedures must be followed as described in OPPD Chemistry Manual, Section CMP-2. Correct analy-tical procedures must be followed as described in OPPD Chanistry Man-ual Section CMP-3.
B.
Verification of analytical instrument accuracy. The instrument (s) used must be checked for proper calibration and function. Any chem-ical reagents used must be verified to be of the proper type, strength, standardization and be known to be free of contamination.
C.
Identification of system ananalles.
The plant operations and main-tenance staffs must be contacted to detonnine if those groups havo taken any action or caused any situation that may have caused the problem being investigated.
D.
Notify the Plant Chemist or Supervisor - C/RP immediately, except as noted below.
Immediato notification is considered to be within two hours of conpletion of the analysis.
These steps ( A through C) may be deleted or modified only with the approval of the Plant Chemist or
I.
PRINCIPLES OF CORRECTIVE ACTION (Continued)
Supervisor - C/RP. The resolution of any "out-of-spec" chemical condition or other unusual variation in chenical control may be achieved by, but not be limited to, adjustment to chenical feed rates, use or disuse of deminer-alizer systens, adjustment by plant operation of systen flow rates, tenper-atures, and pressures, maintenance repair of systems, OPPD modification of sys tens.
II.
SECONDARY SYSTEM CORRECTIVE ACTION (Condensate, Feedwater and Steen Genera-tor Blowdown)
A.
For All Paraneters 1.
When the normal range is exceeded, inttiate immediate investi-gation of the problem, increase the sample frequency to once per eight-hour shif t, and increase blowdown to approximately 1% of the main steaming rate as appropriate. The problem must be corrected and the paraneter(s) returned to the nonnal range within one week.
If this cannot be done, and the para-meter has a itsted abnormal range, power should be reduced to 25% as if the abnormal range had been exceeded.
2.
When the abnormal range is exceeded, reduce power to 25%.
Continued plant operation is then possible while corrective action is taken. Power reduction should be inttlated within four hours of exceeding the _ abnormal range. The problem must be corrected and the paraneter(s) returned to the nomal range within one hundred (100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />).
If this cannot be done, the unit must be shut down as if an immediate shutdown Ifmit had been exceeded.
3.
When an immediate shutdown limit is exceeded, the unit must be shut down wittitTrour hours to prevent rapid steam gener-ator Corrosion.
B.
Additional Corrective Action for pil and Conductivity 1.
Verify that at least 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> have elapsed since any previous secondary system chenical feed alteration (or at least one hour if reactor power is being changed).
Review reactor power and secondary systen chenical feed history for the previous 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
2.
Write a chemical instruction to alter, as appropriate, alka-meen pump stroke.
If alkameen feed is not in service then alter, as appropriate, hydrazine pump stroke.
(If this is Itkely to cause hydrazine to go out of specification, notify the Plant Chenist).
3.
If a pump stroke change of more than 5% appears to be needed during steady state power operation, notify the Plant Chenist immediately; otherwise, immediate notification of the Plant Chentst is not required.
4.
Resample af ter the chemical instruction is implenented, nor-mally within four hours.
.o II.
SECONDARY SYSTEM CORRECTIVE ACTION (Continued)
C.
Additional Corrective Action for Hydrazine 1.
Verify that at least 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> have elapsed since any previous secondary system chemical feed alteration (or at least one hour if reactor power is being changed).
Review reactor power and secondary syster, chemical feed history for the pre-vious 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
2.
Write a chemical instruction to alter, as appropriate, hydra-zine pump stroke.
3.
If a pump stroke change of more than 57, appears to be needed during steady state power operation, notify the Plant Chemist immediately; otherwise, immediate notification of the Plant Chemist is not required.
4.
Resample after the chemical instruction is implemented, nor-mally within four hours.
D.
Additional Corrective Action for Blowdown Rate 1.
For steam generator blowdown out-of-specification low but greater than 9000 pounds per hour, notify the Shift Super-vi sor.
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