ML20235C111
| ML20235C111 | |
| Person / Time | |
|---|---|
| Site: | Trojan File:Portland General Electric icon.png |
| Issue date: | 09/18/1987 |
| From: | Cockfield D PORTLAND GENERAL ELECTRIC CO. |
| To: | Martin J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| References | |
| IEB-87-001, IEB-87-1, NUDOCS 8709240352 | |
| Download: ML20235C111 (33) | |
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Portland General ElectricCoirgsly 1
l David W. Cockfield Vice President, Nuclear September 18, 1987 I
Trojan Nucicar Plant I
Docket 50-344 License NPF-1 i
.Mr. John B. Martin Regional Administrator, Region V U.S. Nuclear Regulatory Commission Crooksido Oaks Offico Park 1450 Maria Lane, Suito 210 Walnut Creek CA 94596-5368 l
Dear Mr. Martin:
Response to IE Bulletin 87-01 In IE Bulletin 87-01, Thinning of Pipe Walls in Nuclear Power Plants, licensees were requested to provide information regarding their programs for monitoring the wall thickness of secondary system piping. Attached is our response to that bulletin.
Sincerely, Attachment c: Document Control Desk U.S. Regulatory Commission Washington DC 20555 Mr. R. C. Bare NRC Resident Inspector Trojan Nuclear Plant Mr. David Kish, Director 9709240352 B70918 State of Oregon PDR ADOCK 05000344 Department of Energy PDR bscribed and sworn to before me this 18th day of September 1987.
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Trojan Nuclear Plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NPF-1 Page 1 of 14 i
RESPONSE TO IE BULLETIN 87-01 In resporse to Nuclear Regulatory Commission (NRC) Bulletin No. 87-01,
" Thinning of Pipe Walls in Nuclear Power Plants", the following is submitted.
Piping at the facility was designed and fabricated to the following 1.
standards (
Reference:
Piping Design Package M-301):
Main Steam American Society of Mechanical
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Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code Section III, Class 2 American National Standards Institute (ANSI) B31.1 Extraction Steam ANSI B31.1 Auxiliary Feedwater ASME B&PV Code Section III, Class 2 ANSI B31.1 Main Feedwater ANSI B31.1 (Outside Containment)
Main Feadwater ASME & B&PV Code Section III, Class 2 (Safety-Related)
Steam Generator Blowdown ANSI E31.1 Heater Drains ANSI B31.1 2.
Trojan has experienced erosion / corrosion of secondary system piping including extraction steam piping, heater drain piping and main feedwater system piping. Portland General Electric (PGE) has expen-ded considerable effort to monitor erosion / corrosion and established programs which consider the following factors:
All high-energy (greater than 220*F) secondary systems piping is a.
included in the Erosion / Corrosion Monitoring Program.
Each annual refueling outage, a sample of components in high-energy secondary piping is selected to examine to monitor pipe wall thickness. Points to monitor are selected based on industry and Electrical Power Research Institute (EPRI) identified factors including:
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(1) Previous measurement results.
(2) Size, rate and location of observed thinning.
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i Trojan Nuclear Plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NPF-1 Page 2 of 14 (3) Environmental conditions of flow velocity, system tempera-ture, 1H, and oxygen content.
(4) Piping geometry.
l' (5) Interval between last measurement and predicted time to d
reach code-minimum thickness.
(6) Failures at similar locations based on industry and Plant experience.
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b.
Examinations are made during each ennual refueling outage on the selected program sample.
Examinations are made using manual ultrasonic thickness measur-c.
ing techniques. Where practical, these examinations are supple-mented by visual examinations.
I d.
Repairs or replacements are made on any component with a predic-ted remaining time to reach code-allowabic minimum wall thick-ness of less than one operating cycle. This prediction is based on a conservative estimation of erosion / corrosion rate that includes a safety factor of two.
3.
Secondary systems piping material is generally manufactured to specifications (such as American Society for Testing Materials (ASTM) A-106, Grade B) that do not specify chromium or other trace alloy amounts.
Since the amount of trace alloys is not known by specific analysis, this is not considered in selecting points to be 4
monitored. piping configuration, pH, system temperature, bulk-fluid velocity, and oxygen content are considered. See response to 2.a.
above.
4.
A program chronology follows detailing Trojan programs for previous refueling outages.
1982 The Erosion / Corrosion Monitoring program was developed as a a.
result of a January 1982 extraction steam supply elbow failure.
The scope included measurements on all 35 feedwater heater extraction steam supply elbows including two 18 inch by 42 inch tee areas from the crossunder piping.
Examination was also performed on approximately 100 data point locations on the 42 inch crossunder pipe at the outside elbow areas where the
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steam velocity and moisture content is the highest. All inspec-tions were performed to specifically measure wall thickness.
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Trajan Nuclear plant -
Mr. John B. Martin
' Docket 50-344 September 18, 1987 License NpF-1 page 3 of 14 b.
The piping' examined above was measured using manual ultrasonic.
' thickness measurement techniques.. Minimum design. wall thickness for No. 5 heater steam supply is.0.131 inches; No. 6 heater steam supply is 0.142 inches; and No. 7 heater' steam supply is 0.218 inches.
The results of the examinations showed wall thinning, but no c.
areas which were below minimum wall thickness. The worst-case component found was No. 3 elbow in. heater SB, where minimum code l
wall thickness is 0.131 inches and the elbow showed 0.154 inches.
This represented a predicted margin of six months to reach mini-mum wall thickness.
In addition to this component, five elbows and one straight pipe section was identified to have predicted lifetimes of less than 24 months, which was considered unacceptable.
d.
In 1982, 6 elbows and one 6 foot section of piping were replaced.
Recommendations were made to replace an additional 3 elbows in i
1983. A decision was made to replace a number of heavily worn pipe sections with new pipe that had a 0.100 inch thick layer of i
I stellite-6 in areas where high-velocity' moisture laden steam is common.
l 1983 The 1983 program continued the monitoring of high-pressure a.
extraction steam lines following the piping failure of 1982.
This program identified two new areas where erosion was occur-ring. The first was within a turbulent area of the No. 6 and No. 7.feedwater heater extraction steam piping as it leaves the high-pressure turbine, and the second was straight pipe runs in the vicinity of flow disturbances.
Erosion was found next to fleid welds with backing rings, next to shop welds without back-ing rings, next to thermal wells and pressure taps, and as pre-viously identified, within elbows. Examination was performed in new sample areas as well as 12 of the 35 elbows inspected in 1982.
b.
All piping was examined using manual ultrasonic thickness measurement techniques. High-pressure extraction steam pipe to Nos. 5, 6, and 7 feedwater heaters was examined including 12 elbows, 27 field weld locations and 14 shop weld locations, three 30 foot straight pipe sections with 12 point circumferen-tial readings recorded every 6-to-12 inches, several tees and reducers and the two 1 inch warmup lines between the high-pressure turbine casing and the No. 7 heater extraction pipe.
Low-pressure extraction steam pipe to Nos. 1, 2, 3 and 4 feed-water heaters was examined including piping within the condenser, h
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Trojan Nuclear plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NpF-1 page 4 of 14 piping adjacent to the low-pressure turbine,. and elbows adjacent to Nos. 3A and 4A feedwater heaters. 'The moisture separator
'rehester tank normal drain lines were examined at eight in-creaser locations following control valves. High-pressure turbine inlet and discharge piping wcs examined where the l
42 inch crossunder piping leaves the high-pressure turbine and one section of 36 inch steam supply piping to the high-pressure turbine. Heater drain pump discharge piping elbows where the j
line enters the heater drain tenk were examined due to high-flow velocity.
The results of the reinspected high-pressure extraction steam c.
piping to Nos. 5, 6, and 7 feedwater heaters elbows showed no significant changes from the 1982 examination.
Seven of the 412 welds in this piping were found at or below minimum code-allowable wall thicknesses. The two 1 inch warmup lines showed significant erosion to less than 0.080 inches (0.218 code mini-l mum). No problems were found in the low-pressure extraction j
steam pipe to Nos. 1, 2, 3, and 4 feedwater heaters. Two of the eight increasers examined in the moisture separator reheater tank normal drain lines were found within 0.030 inches above l
minimum code-allowable wall thickness. No problems were found in the 42 inch crossunder piping or the 36 inch steam supply piping to the high-pressure turbine. No problems were found in the heater drain pump discharge piping.
d.
Due to fitup problems experienced with using stellite coated piping in 1982, a change was made in 1983 to 304L stainless steel for all replacement pipe and elbows. This decision was I
made to reduce installation costs while still assuring longer pipe life.
In addition to the scheduled (from 1982) replacement of three elbows, all four high-pressure extraction lines were replaced as they leave the high-pressure turbine. This area included the seven welds identified below minimum wall. New welds were made without the use of backing rings to reduce flow disturbances. The two 1 inch warmup lines between the high-pressure turbine casing and No. 7 heater extraction piping were replaced with stainless steel. Also replaced with stainless steel were the two piping inercasers in the moisture separator reheater normal drain lines.
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l 1984 The 1984 Erosion / Corrosion Monitoring program again emphasized a.
piping in the high-pressure extraction steam piping system where industry experience had indicated concerns, portions of the piping examined during 1982 and 1983 were reexamined in Nos. 5, l
6, and 7 feedwater heaters.
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s Trajcn Nuclocr P1:nt Mr. John B. Martin Docket 50-344 September 18, 1987 License NPF-1 Page 5 of 14 b.
All piping was examined using manual ultrasonic thickness measurement techniques. High-pressure extraction steam pipe to Nos. 5, 6, and 7 feedwater heaters was examined, including i
10 elbows, 2 tees and 1 straight section of piping downstream of No. 4 elbow from No. 7A feedwater heater. Baseline values were also obtained on the five new stainless steel elbows which were installed during the 1984 outage replacing carbon steel components.
The examination showed all areas above minimum code-allowable c.
wall thickness with greater than 24 months predicted time to i
reach code minimum. Based on results obtained, 5 elbows and 1 straight pipe section were recommended for replacement in 1985.
d.
PCE continued to use 304L-type stainless steel to replace carbon i
steel components during the 1984 refueling outage. A total of 5 new elbows were installed based on trends established during 1
previous examinations. No piping / components were identified as non-conforming during the 1984 examination program which would require immediate replacement.
1985 The scope of the 1985 program was comprised of two parts. Based a.
on experience from previous years, portions of high-pressure extraction steam, steam bypass and heater drain lines were cho-i sen as initial sample points. When components in this sample were found to be below minimum code-allowable thickness, the sample was expanded to include all elbows and tees in the ex-traction steam system which had not been replaced since Trojan startup in 1975. The basis behind the expanded program was the uncertainty associated with an apparently accelerating erosion /
i corrosion rate. The second part of the anticipated monitoring program was based on areas identified as possibilities in a con-tractor report detailing flow velocities, temperatures, pres-3 sures and fluid type (liquid, steam or two-phase) in all secon-1 dary piping systems with temperatures greater than 250*F.
The major impact in scope of this report was to expand sample areas into the main feedwater pump (HFWp) discharge piping, MFWp re-circulation piping, steam trap discharge piping and feedwater heater vent piping.
- b. through d.
Due to the extent of piping examined, an excerpt from the 1985 refueling outage report is attached (Table 1) which summarizes areas examined, results of measurements and replaced components.
Because material was not available in all cases to replace com-ponents with stainless steel, some components were restored to l
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~ Trojcn Nuciser Pitnt Mr. John B. K:rtin Docket 50-344 September 18, 1987 License NPF-1 page 6 of 14 l
the as-designed condition using carbon steel. Continued' monitoring and subsequent replacement was anticipated for these items. piping replaced as a result of the monitoring program included:
Twenty-two elbows and 80 feet of extraction steam piping.
Four increasers in the heater drain system.
Several small sections of small-bore piping.
Steam generator blowdown tank vent condenser discharge piping.
Fourteen inch heater drain pump discharge piping.
1986 The scope of the 1986 Erosion / Corrosion Monitoring program s.
incorporated recommendations from the 1985 EPRI workshop on erosion / corrosion in~the nuclear plant steam piping. The piping sample for the 1986 examinations also factored in previous plant and industry experience and likely areas identified by the con-tractor report received in 1985. These areas. included piping downstream of. steam traps, main steam piping, feedwater heater vents, air ejector steam supply piping, heater drain pump dis-charge piping, heater drain tanks, moisture separator reheater (MSR) crossunder piping, extraction steam supply to the MSR and the steam generator blowdown tank, i
b.
piping was examined using manual ultrasonic thickness measuring i
techniques and visual examination techniques where possible.
I The steam generator blowdown tank was also examined by magnetic j
particle testing. piping examined included the following:
l First two main steam line elbows downstream of "B" steam generator.
Main steam drain line steam traps Nos. I through 9.
First elbow upstream of the stop valve on the "C" main steem line.
West MSR crossunder piping (visual only).
No. 3 and No. 6 feedwater heater drains.
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Trajtn Nuclotr plcnt i[
Mr. John B. Martin Docket 50-344 September 18. 1987 License NPF-1 Page 7 of 14 Heater drain system piping:
Pump discharge Pump discharge vents MSR tank drains Heater drain tanks (2) l Small-bore piping vents on feedwater heaters Nos. 3 through 7.
Four inch steam lines to the risin feedwater pumps (MFWp).
Main feedwater pump drains.
Steam piping to air ejectors.
Extraction steam lines for feedwater heatern No. 4 and No. 6.
process steam piping.
Steam generator blowdown (SGBD) tank inlet linec (4).
SGBD vent condenser piping.
SGBD tank.
The following items were identified during the examinations:
c.
Main steam drain line steam trap No. 3 at s' thickness of l
0.097 inches (code minimum 0.069 inches); Nos.'1, 2, and 4 l
1 traps showed less wear (0.110, 0.121, 0.111 inches, I
respectively).
l Two carbon steel elbows on piping from ESR drain tank to heater drain tanks at a thickness of 0.15tuo.181 inches (code minimum 0.148 inches).
I One inlet line to SGBD tank downstream of the control valve at 0.105 inches (code minimum 0.207 inches); others greater than 0.220 inches.
d.
As a result of previous years examinations, the high-pressure extraction steam lines to Nos. 5, 6 and 7 feedwater hasters were replaced with stainless steel piping. Main steam line drain trap No. 3 was replaced with carbon steel returning it to the as-designed condition. A recommendation to replace all 4 drain traps with stainless steel was made for the 1987 outage. The 2 elbows on the piping from the MSR drain tank were replaced, i
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- q Trbjtn Nucisar Plcnt Mr. John B. Martin l "/
Docket 50-344 September 18, 1987 License NPF-1 Page 8 of 14
' Based on dsta obtained, the;cause of the erosion / corrosion was the result of water flashing to steam across the control valve upstream of the elbow prior to entering the heater drain tank.
The carbon steel inlet line to SGBD tank downstream of the con-trol valve was replaced with stainless steel piping.
4 1987 The scope of the 1987. Erosion / Corrosion Monitoring Program was a.
initially divided into two phases. The program was later expan-ded to four phases based on initial examination results.
(1) Based on the criteria of Plant Engineering Procedure (PEP) 30-9, the original (Phase 1) scope of the 1987 outage was:
Two elbows, I tee and a chort section of pipe on the heater drain tank alternate drain to the condenser.
All heater drain tank inlet nozzles and associated in-let elbows.
Two elt>w:r at the discharge of the heater drain pumps.
Seven' albcws, 2 tees,and 2 short sections of pipe on steam generator blowdown piping.
i Pipino and an expander downstream of the isolation valve on the steam seal regulator bypass line (the by-pass is normally inservice).
l' Four elbows and 4 straight sections of pipe on the new j
stainless steel high-pressure extraction lines to the I
No. 6 and No. 7 feedwater heaters.
l Two elbows, 2 expanders and 2 short sections of pipe on the No. 6 feedwater heater drain lines to the No. 5 feedwater heaters.
lj All high-pressure turbine exhaust piping to the mois-ture separator / reheaters.(visual inspection only with selected thickness measurements).
"B" steam generator discharge piping immediately down-stream of the flow restrictor and 1 elbow.
Two elbows,.3 tee and 2 short sections of pipe down-stream of valves on the main feedwater pump recircu-i lation line.
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...--.x Trojan Nuclear Plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NPF-1 Page 9 of 14 One short section of pipe downstream of a pressure con-trol valve and an elbow on the steam supply line to the steam jet air ejectors.
Six elbows and two tees on main steam piping to the main turbine.
The tee at the connection of the high-pressure turbine second-stage extraction line (stainless steel) with the steam supply to the first-stage reheater.
i Small bore piping, including:
Forty-two cibows, two tees and eight straight sectionc of pipe on the No. 5, 6, and 7 feedwater heater vent lines.
Moisture separator / reheater drain piping.
Hester drain pump discharge vents.
Steam trap drain piping.
(2) Institute for Nuclear Power Operations (INPO) Significant Operating Event Report (SOER) 87-3 provided detailed information on the Surry Nucicar Plant event including observed erosion, check-valve failures and secondary issues (Security, Fire Protection System problems, etc). The SOER was evaluated by Trojan Plant Engineering. Some prelimi-nary information on Surry was made available to industry.
Based on the preliminary information, the following were added to the 1987 outage scope:
One straight section of pipe downstream of the feedwater pump suction flow venturi.
Three 90' and three 45' elbows at the main feedwater pump suction.
Two 45' elbows at the feedwater inlet to the No. 4 feedwater heater and two at the inlet to the No. 5 heater.
Some additional heater drain pump discharge piping.
(3) 1985 and 1986 data was rereviewed when below minimum wall thickness areas were identified on the main feedwater pump discharge and recirculation piping. Based on the review, the following was added to the 1987 outage scope (Phase 3):
The 30 inch diameter tee and piping at the discharge of the No. 7 feedwater heater.
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Trojan Nuclear plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NPF-1 page 10 of 14 V
r Piping downstream of a main steam dump valve and an upstream elbow.
l One elbow, 1 expander and 1 tee on the steam generator l
blowdown tank discharge piping.
Two expanders and downstream piping on the second stage reheater drain tank to the No. 7 feedwater heater.
Two expanders and downstream piping on the first stage reheater drain tank to the No. 6 feedwater heater.
(4) The 1987 inspection scope was expanded as problems were found. This expanded scope (phase 4) is described below.
As a result of thinning observed when inspecting the feed-water pump recirculation piping, the following was inspected:
Eleven elbows and a large section of straight piping on the recirculation line.
Two tees, two 45* elbows, two 90* expanding elbows, and 3 elbows on the main feedwater pump discharge piping.
As a result of problems found when inspecting the heater drain pump discharge piping, 2 tees, 3 elbows and over 100 feet of piping on tha heater drain pump discharge were added to the examination scope.
Inspection of the 30 inch tee on the discharge downstream of the No. 7 feedwater heaters led to inspecting 4 toes and 4 elbows on 14 inch feedwater piping.
As a result of the thin wall discovered in the straight piping containing the "B" main steam line flow restricting venturi, the following was inspected:
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piping containing the "A", "C" and "D" steam flow venturis.
Ten elbows and a section of straight pipe it steam pip-ing leaving the steam generators.
piping containing the feedwater flow venturi.
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Trojaa Nuclear plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NpF-1 page 11 of 14 The inspection of the feedwater flow venturi piping re-vealed areas below minimum wall thickness and prompted the examination of additionni feedwater system piping. This consisted of:
One elbow at the suctions of a heater drain pump.
Eleven elbows and 1 tee between the main feedwater i
pumps and the No. 6 and No. 7 feedwater heaters.
Six elbows between the No. 6 and No. 7 feedwater heaters.
Three elbows between the No. 7 feedwater heaters and the 30 inch diameter tee.
Sixteen elbows on the main feedwater regulation bypass valvc lines.
Four elbows and four 45* elbows downstream of the main feedwater flow venturi.
Twenty-eight 45* and 90' elbows on main feedwater pip-ing inside Containment.
b.
All piping was examined using manual ultrasonic thickness measurement techniques. Crid patterns were used to identify locations for future examinations. These grids varied in size from one to four inches depending on the amount of erosion /
corrosion in the area. All 90' and 45' elbows on Seismic Cate-gory I feedwater piping were inspected at 4 inch intervals (measured on the extrados) at 12 points equally spaced on the circumference. Visual inspection of elbows removed from Seismic Category I feedwater piping showed relatively uniform erosion /
corrosion.
Eroded / corroded areas were large enough to be iden-tified by the selected grid.
Visual inspection of removed piping indicated that erosion /
corrosion was occurring at piping welds and in the weld heat-affected zones.
Th'c erosion / corrosion is believed to be caused by flow disturbai res it.wm the welds and possible local surface alloy depletion its the, eat-affected zone.
To inspect for this type of wall thinning, the crowns on all welds to be left in-service were ground flush with the pipe.
The welds and weld heat-affected zones were inspected con-tinuously on the pipe circumference to identify the mininum remaining wall.
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Trajcn Nucl0cr Plant Mr. Jchn B. Martin Docket 50-344 September 18, 1987 License NpF-1 Page 12 of 14
. Visual. inspection of piping removed from service indicated the initiation of minor thinning. Ultrasonic examination revealed minor thinning over approximately 4 feet of straight piping. In order to ensure that this type erosion / corrosion was identified, all straight piping left in-service was scanned for the thinnest point on the circumference at 12 inch intervals. This ensured that both uniform thinning and " tiger striping" would be detected.
Subsequent visual examination of the straight section of piping that was removed did not reveal any erosion / corrosion patterns.
The. internal surface was covered by a fairly even protective oxide film as expected. The measured. thin areas of the 4 feet of piping may have been due to a combination of minor general wear and manufacturing eccentricity. Metallurgical analysis will be performed by the PGE Analytical Lab on several samples removed during the outage. 0ther portions of the feedwater piping have been requested by the NRC and EPRI for their independent analysis. Results are not available at this time.
Bench mark reference points were made on some piping to allow similar grid locations in subsequent examination programs. Pip-ing examined is described above.
Thickness measurement results for the Seismic category I feed-c.
water piping are attached. The attachment (Table 2) details pipe examination locations, measured thicknesses, predicted erosion rates and the status of piping. Other items which were found unacceptable are detailed in Part d which follows.
d.
The following piping was replaced as a result of the 1987 examination for erosion / corrosion:
MFWp discharge and recirculation piping.
One heater drain pump discharge elbow.
No. 6 feedwater heater vent piping.
Numerous steam trap inlet and outlet piping.
Eight fittings immediately downstream of the feedwater flow venturi.
Sections of piping downstream of the feedwater isolation valves.
Nineteen feedwater line fittings inside Containment.
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Trojan Nuclear Plant Mr. John B. Martin Docket 50-344 September 18, 1987 License NPF-1 page 13 of 14 185 feet of feedwater piping inside Containment (the majority of which was replaced to facilitate access to fittings).
Twelve welds on feedwater lines inside containment were repaired.
5.
Based on previous experience and lessons learned during the 1987 refueling outage with feedwater, PGE is reviewing the current monitoring program and implementing the following enhancements for future erosion / corrosion monitoring programs and sample point selec-tion criteria:
a.
The Erosion / Corrosion Program procedure will be revised to re-flect the exy'-lence gained in 1987 and the recommendations pro-vided by an spendent consultant. The revision will include:
More definitive guidance on the selection of piping to be inspected and on sample size expansion.
Standardization of ultrasonic thickness measurement and recording techniques to allow year-to-year comparison of data.
More definitive guidance on the evaluation of data includ-ing computerized evaluation of erosion / corrosion rates using the EPRI CHEC Program, b.
A detailed evaluation of 1987 data will be completed to support the selection of piping to inspect in 1988. This evaluation will include:
Determining wear allowances on piping components using baseline data for new replacement fittings and pipe sections.
Selecting a sample of the replacement components to exarine in 1988 to esteblish erosion / corrosion rates.
Selecting a sample of components not replaced in 1987 to reexamina in 1988 to establish actual erorion/ corrosion rates.
Calculate erosion / corrosion rates using the EPRI CHEC Pro-gram and calculating remaining time to reach minimum wall thickness. Any component with a calculated remaining time of less than 2 years will be reexamined in 1988.
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.a Trojan Nuclear Plant Mr. John B. Martin 1-Docket 50-344 September 18, 1987 License NPF-1 Page 14 of 14 Establish a data base to allow trending of erosion / corrosion c.
data:
Generate simplified isometric drawings on Computer-Assisted-Drawing system.
Identify each fitting, pipe section and weld.
Input all components and previous data into the EPRI CHEC Program.
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