ML080710492

Transmittal of Annual Operating Report for 2007

ML080710492
Person / Time
Site:	Columbia
Issue date:	02/29/2008
From:	Atkinson D Energy Northwest
To:	Document Control Desk, Office of New Reactors
References
G02-08-033
Download: ML080710492 (19)

Text

Dale K. Atkinson EN ERT Y Columbia Generating Station P.O. Box 968, PE08 Richland, WA 99352-0968 Ph. 509.377.43021 F. 509.377.4150 dkatkinson@energy-northwest.com February 29, 2008 10 CFR 50.46(a)(3)(ii)

G02-08-033 10 CFR 50.59(d)(2) 10 CFR 72.48(d)(2)

U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555

Subject:

COLUMBIA GENERATING STATION, DOCKET NO. 50-397 INDEPENDENT SPENT FUEL STORAGE INSTALLATION, DOCKET NO. 72-35 2007 ANNUAL OPERATING REPORT

Dear Sir or Madam:

Enclosed is the annual operating report for Columbia Generating Station for calendar year 2007. This report is submitted pursuant to 10 CFR 50.46, 10 CFR 50.59, 10 CFR 72.48, Regulatory Guide 1.16, Guidelines for Managing NRC Commitment Changes (NEI 99-04),

and Licensee Controlled Specification 1.7.8. There are no commitments being made to the NRC by this letter, however, one existing commitment has been changed.

If you have any questions or desire additional information pertaining to this report, please contact Mr. MC Humphreys at (509) 377-4025.

Respectfully, DK Atkinson, Vice President Nuclear Generation & Chief Nuclear Officer

Enclosure:

Columbia Generating Station 2007 Annual Operating Report cc:

EE Collins, Jr. - NRC RIV CF Lyon - NRC NRR Director, SFPO - NRC NMSS NRC Sr. Resident Inspector - 988C RN Sherman - BPA/1399 WA Horin -Winston & Strawn INU

" I °,.>

-P*"i,,,*

4, 0,J L

Z ENE RGY NORTHWEST 070033

COLUMBIA GENERATING STATION 2007 ANNUAL OPERATING REPORT DOCKET NO. 50-397 DOCKET NO. 72-35 FACILITY OPERATING LICENSE NO. NPF-21 Energy Northwest P.O. Box 968 Richland, Washington 99352

Columbia Generating Station 2007 Annual Operating Report

"..,Table of Contents Section Pae*

1.0 Reporting Requiremet s 1---"

- 1 2.0 Summary of Plant Operatis.

2 3.0 OutageS6and F0fced Reductions in PoWer--------

3 4.0 Sealed Source ContaMniinatiobn-5 5.0.

Fuel Performance.

6 6.0.10 CFR 50.46 Changes or Errors. in ECcS LOCA Analysis Models-----*6 7.0 0 CFR 50.59 Changes,, Tepss,.and.Experiment s--

7 8.0 10 CFR 72.48'Ch'ange"s*, Tists, and Experiments 14 90 Regulatory Cmmient Changes (NEIP ocess) --------...

Columbia Generating Station 2007 Annual Operating Report 1.0 Reporting Requirements The reports in this document are provided pursuant to: 1) the requirements of Licensee Controlled Specification (LCS) 1.7.8, ".Sealed Source Contamination;" 2) the requirements of 10 CFR 50.'46, "Acceptance Criteria for Emergency Core Cooling Systems for Light-Water Nuclear Power Reactors;" 3) the requirements of 10 CFR 50.59, "Changes, Tests, and Experiments;" 4) the requirements of 10 CFR 72.48, "Changes, Tests, and Experiments;" 5) the guidance contained in Regulatory Guide 1.16, "Reporting of Operating Information-Appendix A.Technical Specifications," Revision 4, August 1975; and 6) the'guidance contained in NEI 99-04, "Guidelines for Managing NRC Commitment Changes', Revision 0, July 1999.

Licensee Controlled Specification 1.7.8 requires a report be submitted to the, Commission, on an annual basig'if'seale'd's'urce or fission detector leakagetests reveal the presence of greater than or equal to 0.0.05 micro*uries of removable contamination.

Regulation 10 CFR 50.46(a)(3)(ii) requires, in part, that for each"(non-significant) change to or for each error discovered in an acceptable Emergency Core Cooling System (ECCS) performance evaluation modelor, in th"e appliciation of such a model that affects the temperature calculation, the applicant oricensee report the nature of the change or error and' th-e estim-at*d effect on th*e limiting ECCS analysis to the Commission at leastannually asspecified in 10,C.

50.4.

Regulation 10 CFR 50.59(d)(2) requires that licensees submit, as specified in 10 CFR 50.4, a report containing a bnef description of any changes, tests, and experiments, including a summary of the evaluation of each., This report must be submitted at intervals not to exceed 24 months.

Regulation 10 CFR 72.48(d)(2) requires that licensees submit, as specified in 10 CFR 72.4, a report containing a brief description of any changes, tests, and experiments, including a summary of the evaluation of each. This report must be submitted at intervals not to exceed 24 months.

Regulatory Guide 1.16 states that routine operating reports covering the operation of the unit during the previous calendar year should be submitted prior to March 1 of each year. Each annual operating report should include:

A narrative summary of operating experience during the report period relating to safe operation of the facility, including safety-related maintenance not covered elsewhere, Page 1

Columbia Generating Station 2007 Annual Operating Report For each outage or forced reduction in power*'of over20 pOercent of design power levellwhere'the reduction exends for more than four hours:

(a)

The-proxim.ate lcause and the system and majot, component involved (if

't-he, o.t6age or forced reduction in power involved" equipment nialfunction).

()

"A brief discussion of (or ireference -reports:of) any reportable

"courrence-pertaining tothe OUtage or power reduction.

(c)-

Corrective action tak"e to reduce:the probabilityof recurrence, if appropriate (d)'

Operating-timeloisttas a result 6f theoutage or power reduction.-

.(e)-A description of major*safety-related; corrective maintenance-performed S:-,

during th6 outage or.power reduction, including the system and S.. componiet in~olve'd-and identifiCation of the critical p0ath activity dictating

' thea gegth

-f theoouttge r power reduction.

(f)

A report of any single release ofradioactivity or single radiation exposure specifically associated with the"Outage, which accounts for-more than ten percent ofithe'allowable annual values.

• -A tabuItion ono an annual basis of the number of station, utility and other perisornel (including contrac tors receiving exposures greater than 1 00-.

mreIi"brnr/year and their a'ssociated man.rerm exposure according to work and job functions. (Columbia Generating Station [Columbia] License Aimendrme§nt 190 eliminated the requirement to report this information.)

• lndications of failed fuelresulting from irradiated fu'el bieminations.including eddy current tests, ultrasonic tests, or visual examinations completed during the report period.

"Guidelines for Managing NRC Commitment Changes," NEiJ99-04* is an NRC-,

endorsed method for licensees to follow when managing or changing NRC commitments.. For commitmbnt changes that meet certain critria&,

the guidance specifies that the NRC-staff be notified of the change's eitheranhually-dr al6ng with Final Safety Analyses Report (FSAR) updates required by 10 CFR 50.71(e).

2.0 Summary of Plant Operations S-'he summary of plant operations is provided in accordance With Regulatory Guide 116,. Re'AsioW4, Setion C.. T.b.(,

Page'2

Columbia Generating Station 2007 Annual Operating Report The-year, begn, with Columbia operating atiý 00% power.,,OnApr8i.8th, 2007, during replacement pf a8failed transformer (E-TR-lN/2)o. n -the. Division 2 120 VAC power supply inverter, technicians lifted the neutral wire at E-TR-IN/2, causing a loss of grouwnd: reference..at,,main: control, room.ppwe*Zrpane..- (E-PP-8AA). Due to the ensuing-power fluctuations operators declared the pjanel.inoperable, entering Technical Specifications Action Statement (TSAS) 3.8.7.A. Prior to exceeding the 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> completion time, management decided to initia.te a controlled reactor shutdown on April 9. ýPlant.stafficompleted the repairs and th.e unit was taken to 99% power on April 15. On May 12, the station began the scheduled refueling and maintenance outage(R-18).. Te.owtage ended 44d-ayslater. when the-operators synchronized the generator to the grid early June 25. QnJ*une-28th, with the plant at 70% power, Operations personnel were transferring lube oil filters on a condensate booster pump (CQND.-P-2B) wben-Ahe, pumpjtrjpped andrthe reactor scrammed on', low water level. The COND-P-2B trip on low oil level was caused by th*filter-transfer and. theino.rrect fi.ter dupleex onfiguraqtio.:, Plant staff corre¢,ted the cýonfiguration and power waS~estQrPd.o lO 0 /, on-July 5. On the afternoon of August 2, operators::-re du.eeatorpo,w.er.to.15%:and removed the main generator from service to.fa~pil,ijtate rep~irs:,on-.thg links-fQr one of the main transformers (E-TR-M1). Repairs were completed and power was returned to 100% on A~ugust6. On August 21,. operators redjuqedupower to~about 60% in

-response to, a'* failed check valve-n;the Digial-.,Eectrl-IHydraujic(DEH) dump valve assembly-that closed a main, ' s.team intercept yalve.- After the check valve was replaced, operators restored power to 100% on August 22. On November 24., jthe operators reduced -ppwer-to, about! 8N.%9.d.ue to.the loss ofqpe of the two reactor feedwater heaters, (RFW-HX.-6B),.,. The: next day, *perators-.reduced power to 70%o

.Support reovery-.of-:the e,ater,.. -Operators. recovered the heater

and restored power-to. 100% on November 25..

Planned power reductions were made routinely during the year for equipment maintenance, su4.eillance testing, control rod manipulations,,and economic dispatch.

j-3.0.. -

Outages and Forced Reductions in Power The, information about the-o.utage.s oqr forced reductions in power is, provided in agqordance with.Regulatory.Guide; 1..16,,, Section C.,1;b..(2).I..

April 9, 2007 (approximately 140 generator off-line hours)

On April 8, during replacement of failed transformer E-TR-IN/2, technicians lifted the neutral wire at E-TR-IN/2, causing a loss, f grqun~d,.reference for power panel.

E-PP-8AA. Due to the ensuing power fluctuations, operators declared the panel

-inope!jrab#e, entering TSAS 3.8.7.A, [LER.-.20Q7-703]-PFior,-to-exc eding the-8 hour completion time, management decided to initiate a. control.led reactor-shutdown on April 9. Repairs were completed and operators synchronized the main generator to the grid early on April 14. The plant reached 99%power on April 15.:

Page.3

Columbia Generating Station 2007 Annual Operating Report The root cause of lifting the neutral wirewas a less than optimal design which established vulnerability and anerror-prone condition.- Co.ntributing causes were less-than-adequate drawing configuration requiring extensive interpretation vs.

identification and application, less-than-adequate, training provided-to.personnel responding to emergent equipment,ýissues, and a less-than-adequate-procedure.

Corrective actions included adding information, to applicable drawingSt modifying the model work order, establishing appropriate training on neutral grounds, and revising the;procedure.*-

May June 25, 20.07 (approximately4-1056 generator off-line hours)

Energy Northwest begarn.:.the,18th refueloutage (R-18) as:planned on May 12.

Activities completed included replacement of the following components; both reactor feedw, ater.heatexchanger3 (RRV-HX-6A and 6B), a 'reactor water recirculationý (,IRRC) pump (RIC-.P-:I,) motor, mechanical seals on both RRC Spumps (.RRCp-IAand 1B), the high pressure core spray, (HPCS) pump and motor, 24 control rod drive, mechanpisms, *;30Qow power range monitors (LPRM), and 6

.,main steam: safety -relief valves ($RV) Repairs were made to RFW-P-1-B,,

,extensive transformer yard corrective and preventive maintenance was performed, aynd the digital electror-hydraulic (DEH) control: system upgrade projectiwas completed.

,The main generator wjs syn-hronized to the grid again at 00:13.on June 25, officially endjing the:R 1&8 outage.

During. R-1-8, one individual received a planned single exposure in excess of 10% of the allowable annuil-occupationa!-dose limit of 10, FR 20. That individual was performing hose hookups and disconnects for chemical decontamination of the reactor,water cleanup (RWCU) system, The individual received a whole body dose of 546 mrem (as measured by an electronic dosimeter) during a single radiological controlled area -(RCA) entry. Thej ndividual's TLD reading (the dose of record), for

-..the entire outge duration, was,661 mrem..

June 28, 2007 (aapprpximately 94 generator off-line hours),...

On June 28th, the plant was operating at:70%,power duepto aproblem with COND-P-2A. While operations personnel were transferring lube oil filters on COND-P-2B, the pump tripped and The reactor scr*mmed on, low water level. [LER-2007-004]

.Operators synchronized the generator to the grid.early on July 2. Power reached

,100% oon July 5;.

Root causesof the CQNDP-2B trip were less-than-adequate configuration control for the COND-P-2B lube oil filter valves, and less-than-adequate risk assessment performed by the operating crew. Corrective actions include revisions to applicable procedures, implementation of an operational decision tree applicable to emergent low-level issues, and correction of the filter valve configuration.

Pag 4

Columbia Generating Station 2007 Annual Operating Report August 2, 2007 (approximately 68 generatoroff-lineHh06'rs)-

On August 2, operators reduced reactor:powerto, 15% in order-Itorerove the main generatorfrom service. Theý generator was taken off the grid So that technicians could repair failing connection-interfaces on the disconnect links forWone of the main step-up transformers (E-TR-M 1).: Repairs were completedardithe'prlant was returned to100% power on August6:.

The root causes of the condition were the lack of inspection-for-replacement: criteria for the main transformer link plates and less-than-adequate joint preparation in the work instructions.- Corrective: actionsinglude a, procedre6 reviSion to inClude inspection-for-replacement-criteria: and joint ieparation Instf:uctions.=.

AuguSt 21, 2007 (approximrately 24 ho~uist redUced ýpoWer)"::"

'On the night of August 20, operators responded to a DEH".trouble' aiarnf and found a main steam low pressure turbine intercept Valve _hed closed, due to aleaking check valve in the DEH dump valVe assemb ly'. Operators:iimmediately began reducing power to 62%. The check'valveýWas~rplacedand-the&DEH,,and main steam valves were returned to normal operatiori.

The returnff to 0%-power was delayed-to resolve problems with speed control-on" an RF-W-pump, Qperators restored the plant to 100% power on August 22.

The cause of the failed check valve Was the.1993,system leafninrig using a cleaning fluid containing amines, which have been shown tol initiate stress.cOrrosidnc-racking in copper alloys. Corrective actions include replacement of all of the check valves on the dump valve assemblies for the intercept; reheat, thrbttl6, and govern6or valves dUring the neýt forced oUtage, if practical, or4hel19t, refueling Outage (R-I9),

Also, a stampl6 of Copper alloy conponerits on the trbine-Vaiaeactuators will be replaced,during R-19 to determine. extent of damage-tobothe. copper components.

November 24, 2007 (approximately,32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> at-reduced power)

On November 24, operators reduced'-power tabout 80% -in *esponse to the RFW-HX-6B trip on high level. On November 25, the operators reduced power to 70% to support recovery of the heatiexchanger. After operators. returned RFW-HX-'6B to servic,', they'restore, reactor power to 100% at 18:35. ;.

i The'heat-exchaner tripped due to-afalse 'high.level:signal. Further ihvestigation revealed a failed level switch-..Preventive mainterndanceactiVitleS.will'be enhanced for the switch and others in similar configurations and environments., A plan will be developed by engineering for the removal of the single point vulnerability caused by

-the lack of diversity or redundancy in the logic of the level sWitchýesfor RFW-HX-6A and 6B.

4.0 Sealed Source Contamination There were no incidents of sealed source contamination during 2007 that required reporting in accordance with LCS 1.7.8.

Columbia Generating Station 2007 Annual Operating Report 5.0 Fuel Performance The fuel. integrity information is provided in compliance with Regulatory Guide 1.16, Section C.1.b.(4), and FSAR Section 4.2.4.3, "Post-Irradiation SurveillanCe."

No fuel failures were-identified during calendar year 2007 (Cycles 18 and19).

This conclusion was based on; readi.ngs of..offgas radioactivity from the pre-treatment process radiation monitoring system.

The, sum"of-ýsix.re dings have stayed, considerably below 300 micrdCi/sec4, one of the INPO thresholds for fuel failures. The values for the Xe-133 activity and the

• Xe4-133/Xe-1351,and Xe-1 38/XeA-I 3 activityý ratios have: been within the rahge for an intact core.

Since Columbia':didf'notexperien-ce. any f.0e defects or, gross cladding anomalies during Cycle. 18,.uel inspections were not: required during R-18 by FSAR commitments;, However,,-inspections were7 performed during the R18. outage on fou'r assemblies ýthat* resided in the~core for. one to two cycles. These inspections are in"responSe,,to the Energy, Nortbwest;implementation, in recent years,.of

.several newwaterchemistry programs.-The programs, include noble metals F,.-:addition;,iron and 2zinc injection.;;and, hydrogen water chemistry injection., Visual inspection-:restuJts indicated normal fuel performance. for-both once: and twice S -b.urned fuel

.An additionrto-fuel visual inspect-ions, fuel channel bow measurements on 62 twice-burned ATRIUM-i0-assemblies werepe.rformed to confirm channel performance in;1the Columbia core rinr. response tothe potential concern on, channel bow observed in other BWRs with Zr-2 channels that were exposed to control blades early in life. The channel performance. was-*normal and. there was no indicationo.f shadow corrosion inducead-bow.

6.0 10-CFR 50.46 Changes orEfrotrsin EC.CS LOCA-Analysis Models The non-significantchanges;,and:errors, in ECCS cooling performance models are provided in compliance with 10 CFR 50.46.

The Westinghouse methodology was used to license SVEA-96 fuel in the Columbia core. rn error was.discovered in the Westinghouse ECCS loss of coolant accident, (LO.CA) analysismpdel which involved modeling of thecore

-inlet. side-entry. orifice....

vEyaluatio nby Westinghouse indicated there was no

-impact.on peak,.clad. temperature, (POT),from this error.. Therefore no revisions were made to,tbe :Col~umbiaLOCA.Analysis Report during,2007 Papa 6

Columbia Generating Station 2007 Annual Operating Report The AREVA methodology was used to license ATRIUM-i0.fuel.,in the Columbia core. No errors were discovered in the AREVA EGOS LOCA analysis model and no, revisions were made~to.the Col6mbiarLOCAAnalysýis Report during 2007.

7.0 10 CFR 50.59: Changes, Testsiand Experiments, This section contains the summary of the evaluations for activities implemented during 2007 that were assessed:pursuant, to G10 CFR50:59::requirements:

Energy Northwest evaluatedthe, changes summ-&iz-d below.:and'cdletermined prior NRC approval was not required.

Plant Design Change (PDC) 4661,(Evaluation. 5059-06.-0002)..

Thelow suction trip set point'of the RFW-_pumps-'.was: raised within.'the iprocess design limit to optimize the protection -of the pumps -Thedesignfunction of the RFW system is.to provide a reliable:source of high purity feed~water to the reactor

.during'both-normal operations and-anticipatbdj ran-ient c¢nditions-Raising the RFW pump set point, staggering thes-etp.dints,.aid -inrstaHing..theIbypassý switch

L were'actions designed to improveýthe reliabfility'ofthe RFW'.system*.-'The7 set point change prevents the pumpzfrom..operating below its required. net positive suction head (NPSH). Staggering the set points prevents the simultaneous loss of both feedwater pumps and decreases the likelihood of losing both pumps during a low pressure transientr.r The '!inclluio*':of a low power (*25%)_:bypass switchý prevents~a loss of feedwatertrp when-s9uct6n.pressures sless I

than the trip set, points but is greater than thMe required operating pressure.

S Ealuaion,;Summnary::.....

This evaluation has shown that no'indrease in frequenty'of occurrence or.

consequences of an accident or malfunction of a structure, system, or component (SSC) important to safety previously evaluated in the FSAR will occur. ;.Thic-;designGhange; mairitains the: FSAR-design function 'a-ndd does not create an accident of a different type or a malfunction of an SSC important to safety:with adifferent. result thain previouslyzevaluated in the'FSAR..-,

This activity does not require prior NRC approval.

Plant Design Change'EC 4934 (Ev'aluation. 5059-06-0003)

Energy Northwest r~eplaced the old analog DEH and tubibne trip.systemr-With a digital PLC-based'system that will ',perf.rm-all the~functins, of the existing system but with improved reliabitity and~fault tolerance:,The new. s¥yter inCiorporated the control, protective, monitoririg, anrd testing-functions the existinpsystem, without maintaining the mechanical overspeed trip. The new system provides modes of automatic control for startup, normal operation and shutdown conditions, as well as a manual mode to position the valves.

PageO7

Columbia Generating Station 2007 Annual Operating Report Evaluation' Summar.

No:FSAR described accident analyses are adversely impacted by these DEH modifications. The transients are either a-non-limiting '6vent,:or the results are conservative and-bounding.

The-probability of a turbine missile remains within the regulatory plant-specific threshold Combined Overall Probability (P4):.of.1 X.1107 established in FSAR Section 3.5.1.3. The installation of the new DEH system does not result in an increase in the 'probability:oft4his event.-The diversity of the modified system meets the guidance for diversity forrdigitalIsystems provided in EPRI TR-102348.

Hence, the proposed activity does not result in more than a minimal increase in

,the frequency of ýoccrrence,:of ah accidentpreviously evaluated in the:FSAR.

The new system retains all of the control functions of the. existing system. There are no new control functions that directly interface with important tQ-:safetV.SSCs.

The--4uricItion -of the'replacement DEH sysbtemwill not change the operating or design parameters:of any other plant system..

The newDEH-system Ihas beenmdesignedras a highly reliable system. This.

design-is achieved-through implementation bf a combinationrof using highly relialSle components and-application of triple modular redundant (TMR) faUlt tolerant design.

Engineering:performed',a Failure Modes and Effects Analysis (FMEA) for -the new

• hardware and software to verify that a -single'failure of'the new system is unlikely

.to result in a~plant shutdown or plant transient.

Based on the comparable probabilities for destructive overspeed, improved reliability thruglh redundancy; fault tolerance, 'and a fail-safe design, the-

"deactivation of the mechanical overspeed trip.and the reliance on the electrical ove6rspeed-trip.will provide.,adequate-overspeed -trip, reliability:'

Therefore, the proposed activity does not result in an increase in the likelihood of

-occUrrence of a malfunction of'anh SSC-important to safety previoutly evaluated in the FSAR.

7-Any change in response of the new DEH control system that affects' the results of accident afialyises (input parameter change).is evaluated using existing approved methodologies for accident initiation-and control response to:FSAR described events., No alternative methodology or.changes to an element of methodology is required by the !,,hange-7in control. system functions' of,.responses.

This activity does not require prior NRC approval.

Page:8

Columbia Generating Station 2007 Annual Operating Report FSAR Change LDCN-FSAR-06-064 (Evaluation 5059-06-Q0.0Q.4)-,-..,.

• A new accident-scenario was added-to.the FSAR.I The new scenarioassumes offsite-power.is ava ilable, after,a,-LOCA, while cooling to one residual heat, removal (RHR) heat exchanger is lost. The scenario.posits the-continued running of all ECCS pumps in the absence of cooling from the heat exchanger.

The scenario relies or,,operator.Cation to seeure-,ECCS pumps associated with the non-functionalRRHR ;heatteXchanger.

r The Galculatedi post-.LOCApeaks-uppression pool temperature is, 204.,5FF.* The

.,new accident.scenario can be addressed by o eratoraction, and-remains within design margins for suppression pool temperature and ECCS pump NPSH.

Finally, proceduresi-we.re revised-to -provide appropriatecautions to.the operators for the operation of ECCS pumps in this new scenario.

Evaluation Summary

. General Electric :(GE) identified (10, CFR Part,21:CorTmunication) anew post-accident scenario that is outside theGColumbia,desig n basis and' licensing basis.

The subsequent evaluation identified a resulting non-conformance with analyses for suppressionpool water temperature-during LOCA. ý-n the -absence of operator intervention, this scenario would cause:a higher - uppression pool Jtmperature fthan. riginallyr*calculated, higher than the peak.temperature of 204.50F,.

The scenario added to the FSAR entails the operation of ECCS pumps after the failure of an-RHR heat exchanger to cool. This-differs from.heanalyzed

.scenariosin the licensing basis, The-scenario adds;:heat tothesuppression pool.

The added heat raises the pool-temperature and,,in turn,, lowers the available NPSH for the ECCS pumps.

The scenario is&,similar to LOCA. Case C, documented-in. FSAR.Sectio.n

,-.2.1.,1.3.1.6,-"!ongý-Term-:Accident,,Responses"I That case resulted in,.the highest post-LOGCAcontainment.pressure and temperature., documented in the FSAR. Case C is based upon the following assumptions.

U-. Division.l is not functional.- RIR-A (pump.and heat exchanger) and LPCS are not operating.

2. Division 2 (RHR-B and RHR-C) and Division 3 (HPCS) are operable and functioning.

.3 For.the first 6001seconds of the, accdent, there is no RHR cooling.*

"4. After,600 seconds, the operator performs twoa-tions:.-

ClosesRHR-V-48B, the bypass valve for RHR-HX-I B, causing 100%

of-the RHR flow to pass-through the heat exchanger,..

Secures RHR-P-2C, a low pressure coolant injection pump (LPCI).

Page 9

Columbia Generating Station 2007 Annual Operating Report The assumption of operator action after 10 minutes of the accident was Z considered and accepted by the NRC in the original safety'evaluation report (SER), NUREG&0892. The acceptance was based upon the condition that early initiation of suppression pool cooling be emphasizedinh the plant emergency procedures.

SThe neWscenario0differs'in that Division 1 is assumed functional and the loss of

.a single: RHR heat e6changer is postulated:.The Division 1 low pressure ECCS pumps, (RHR-P-1A and LPCS-P-1) continue to operate until secured by the operator. While the pumps operate, the pump work is assumed to be transferred to the suppression pool as heat. This heat 'ýw6uld be added to Case C's heat, which consists o:

post-a66id'ent core decay'he*6t,

!p'uh~pwbrkof HPCS-P-1 Ind RK*-P-2B, and Spunip work of RHR=P-2C, for'600 seconds.

After 600 seconds, ;ehergy, is removed from the suppression pool by standby

.service~w~ter (SW) via RR-,HX1 B.-'he removed heat is transported to the SW spray ponds, the ultimate heat sink (UHS)., For the scenario depicted in this chan gethe operator is:asýumed to 6secure the Division 1 ECCS pumps, along with theex"tra'LPCi' pump, as1po5stlaled in Case C. Case C remains bounding due t:io the foillwihg 'detetriminations.

I.. 'There is currently'sufficient information and guidance for the operator to

. '"iderntiti:,th'e'newv-scehna*rio, and implemient appropriate rem'ediation.

Existing guidance will be augmented -by fui-ther updates to Iprocedurýes and related training to document this scenario.

-2. There is ample design margmin the Case ý'containmenfanalysis. This m

rijargiri is sufficient to ensure ade1uaae pump NPSH in the absence of operator action for over two hbdrs. Themairgirn is in the form of RHR cooling that occurs during the first 600 seconds of the accident and perf6rmance of the ECCS sirainers..

'Thbe proposed, FSAR change and posited operator actions do not introduce the possibility of a change in the fr*euencqy of an;accideht. The change describes an o~erator' rsponse to a p"ostL'OCA scenhario. The scenario -ilss ofcooling by an RHR heat exchanger'*' is partially described iniFSARa Table 9.2-8,' 'Standby Service Water S stem Failure,Analysis'."" :The opeýator response - securing of ECCS pump$ that are not needed for core cooling - is not an initiator of any accidenft previously evaluated intlhe FSAR.

The proposed FSA

.sceAnario entails, n'chlange to the methodology of the "containment aralysis or rassumptions. In'that analysis, operator action is"-

assumed-lat lo0hminUtes. to secure an unneeded EccS pump, RHR-P-2C'. As discussed in FSAR 'Secti6n 6.3.2.2.6;,"Emergency Core Cooling System Suction Strainers,"kthe-rea"8re"sufficienit: m'argins in the NPSH and suppression,pool' analyses" to, ehs*ure="that the lack of operator action for 20 minutes will not challenge the required NPSH for the ECGS pumps-at-the pump noZzles-or allow PageS 10

Columbia Generating Station 2007 Annual Operating Report cavitation anywhere in thfe suction lines.. Furtber engineering evaluation verified there was sufficient margin such that lack of-operator, action. for over two. hours would not adversely affect ECCS:. NPSH, The, rpesults depicted in the FSAR for LOCA.Case C are unchanged.,

The new scenario does not result in the increase in the frequency of occurrence of accidents that are defined in the FSAR. The new scenariop wi.!..notý initiate any FSAR-described event. Operator.actions to.address.the new eyernt are. consistent with current FSAR descriptions..-

Therejs minimal increase in the likelihood that the' new accident scenario-will increase the occurrence of a malfunction of an SSC important.to safety previously evaluated in the FSAR. Opierator actions toaddress the new event are consistent with current FSAR-descriptions and the guidance provided in procedures and training. Theample margin. in~the containme accommodate excursions from presumed.actiorn,timen.tjoraplriors, c.

Supplemental guidance will be pirovided by'prced ure ieisionrs.:o nddtraining.

The proposedchanges..to the FSAR and postulatedoperator.response to the LOA scenario do not introdcuc* the possibility of a change in the.cohsequences of an accident because neither the new scenarioror. the requiredjresponse is an

-initiator of any accidents. Delays in.operator-response will not introduce new failure mpdes. The nev'scenarijodoes not challenge any asPectQof post-LOCA response or any fission product-barrjer..

The new scenario - loss of an-RHR heat.exchanger-with operation -of all ECCS

.;pumps - does not introduce tIhe. possibi'iity -ofa change in the consequences of a malfunction..because the scenario cannot initiate any malfunctiOns and no new failure modes are introduced.

Engineering evaluation demonstrates that-ample margins..exist, for the presumed delays in the operator action to secure ECCS pu`mps.A tw-'hour delay in operator action,.dpes not introduce-the possibility of a new accident because suppression pool tempera.tures wil re.marin'withri ana*,sed aimitsaid Wiil not initiate any. new accident nor introduce any new fajlure m6de. Accordingly, the proposed FSAR chaingea~nd posited'operator actions donot create an-accident pooseadiern tYPA#

R" c i...e n' t ofa different type than.any previously.evaluated in the.FSAR..

Theý LOGA scen'ario introduced byýAhe F SAR char.e does",

not ihtroduce the possibility of an SSC malfunction with adiffereht result. Expected operator actions - or delayed actions -.do not introduce a new-failure mode. The failure modes implicit in the new FSAk description ara.bounde.d by those described in the.FAR.,The irnstru.ment.ation that'is available,thti* e'otper'atpo, "rovtos tmple information to act up6n and reme'diate th*e.failresi. T Ah6euidance6.f ixeistilrg p."roce dures.will be, augment.d 1o0uly.de61ribth8,new scnar.io,and W*l, relfhforCe, perartor understandihng a.nd respon.e t6"the.faikuresi Existig.

information.and guidance provwdes.the operatorwith thej nformatonrrequired to Page. 11

Columbia Generating Station 2007 Annual Operating Report respond tc the loss of function in one RHR heat exchanger. There is ample margin in-the-containment analysis; to provide the-operator with time to assess

and, respond, to

the? new scenario. Existing -pro cedural guidance will be:

augmented-with additional information that addresses the new F.SAR scenario.

Accordingly, the new FSAR scenario doesnot create, the possibilityof a malfunction of an SSC important-to safety with adifferent result-from those currentl ydescribed in.the FSAR.

The scenario described in the proposed FSAR change does not represent a ch'!lenge ttoany fission product barrier.,

Sl T"he w~etwell: has: a design temperature of,22700F:The original licensing

Jbassor peak suppression poo temperature is 212 0F. The new FSAR scenario doesnot, result-jn eitherof these temperatures being exceeded.

....:2 :,:Emergency-,corecooling isjavailable,- and adequate corq,,cooling will be provided:.Thereispno adversje. impact on cladding temperatures.

, 3T*-he new FSAR scenario does. not affect.drywell cornditions or the ability to performthe-design functions.

The proposed change does not result in a departure from-a method ofevaluation described. inthe FSAR.used: in establishing thedesign bases or-in the safety analyses. Assumptions implicit--in.the, new scenario and supporting engi.eering

..evaluation.are con'sistent with current.FSAR, descriptions. The cu rrent.-pest-LOCA

.containment a~nalysis isunchanged...

This activity does not require prior NRC. approval.

FSAR Change LDCN-FSAR-0.7-002 (Evajuation 5059-07-0002)

This, change, tothe FSAR describes an alternative cooling system for ;the -.reactor pressure. vessel (RPV) and-spent fuel poolI(SFP,). The cooling uses the Division 2 RHR-system and fuel pool-cooling (FPC) system in alternative lineup5,wjth the RPV. cavity flooded to the pool skimmer level andthe SFP. gates removed.

Natural circulation provides reactor core flow. Under the., appropriate conditions, "tl#is alternative cooling, lineup will allow th? removal-of both trains of RHRý shutdown..eooling (SDC) fromservie for -maintenance ativities-during a..;,-

refueling-outage, such. as decontamination of both loops-of RRC system or maintenance of the.RHR SDC suction valves,:RHR-V-8 and, RHR-V-,9.:r

The change includes the followin'g;,:

1. Changing procedures to realign from normal RHR SDC to FPC assist and to the head spray line and both trains of the normal FPC lineup to discharge to the RPV cavity, with the options to secure or not secure any system operation during realignment. The RHR-B SDC lineup remains available during transition to and during initial acceptance testing, while the Division 1, (RHR-A) SDC is assumed unavailable.

2. Increasing the total flow through the four skimmers and two skimmer surge tanks from 3000 gpm during RHR FPC assist-only up to 4900 gpm Pagp* 12

Columbia Generating Station 2007 Annual Operating Report during corncurrent operation of RHR FPCOassist, RHR.discharge through the. head spray line, and-both. trains of FPC discharge;to the RPV.cavity.

3&

3.Providing an.rew procedure lo-establish acceptance.criteria for full reliance

-on.alternative cooling.' These criteria must~be..satisfied beforeL both;trains of normal'RHR*-SDCGbecome unavailable.

J, 4:, Ihstalling jet pumrpplIfgs oil ail twenty jet pump,nozzleg, to:allow: for chemical decontamination of the RRC:l iping anrd to preclude, communication of the chemical decontamination solution with the RPV coolant inventory 5

Installing a flow diffuser tee (with or Without a ball valve) on the RPV cavity head'spray line flange.- ThM ball v-alveWilll be u sedif needed to allow

--;completion df local leak-rrate testing(.l-R-T)"ofh, adýspray isolation valves.

Upon completion of-theBLLRT.;.the ball-valve wouidlbe oper.ed using either

1. af O'a pneumatic or manuargear operato r.:Thediffuser tee will ýredirect the

-discharge flow :horizontally :in-twOdiree-6tior to miiimiz*turbulence for iunderwate r inspection'" activities. 'I additioh, theitde willminimize the potential for foreign material intrusionh:rito th*e-:tea-d :sprayline.

2 Evaluaticin Summary

~i

~

!' Thel heat :removaL. capability of the alternativetcoolin paths:Willrbeverified before

'aking both trainS 1fRHRSDC Unavailabl:e.1:Thereliability: of -the HR and FPC

- systems used in alternative-doolihngis ogli ibly,'different (i.e., RHR uses,some FPC piping in alternative cooling that is nottClass 1 piping, yet is capable of withstanding applicable load combinations of safe shutdown earthquake [SSE]

and operating basis earthquake lOBE.]) 'from wherthese samte.systems are normally aligned to perform their design function of decay heat removal..

Alternative coling is not an initiator;"td oanyacdcdentit'ýnr'does.itintroduce a new failur, inode.-T herefore, the consequencesobf previo*usly analyzed-accidents bound this activity: For the same reasons, this activity does rit'create the possibility fot a~hew type. bf, acbident ormalfuNction' not previously analyzed.

TKher{fore,'the conisequen'ces of this activity remain :bOunded, The fission product 5

barrie"rf rostaffected by.this activity, iS.thN fuel6cladding., This*activity-is performed during: refueling with the cavity flooded. The water covering the:fuelin the' SFP and ýthe PV Will'be at atmospheri0`pressu'e plLis tliihe'ladof water :oVer'the top of thefuedl. The fuel cladding limits-Will'no-t be exceeded as long as the fuel is covered by water under thesee,;obnditiors and the fuel is -subcritical.

Administrative controls are in place to prevent an accident whereby the alternative cooling activity can cause a loss of water'inventory in the SFP or RPV of.affeb-ftreactivity.

..-This activity does: not require prior NRC approval..

7 P'ate, 13

Columbia Generating Station 2007 Annual Operating Report Condition Report CR 2-07-95255, Accept-As-Is Disposition (Evaluation 5059-07-0003)

The CR documented the ýlossof 0a brush ihthe RPV during cleaning and visual in'sp~etion' of RPV inter'nafs: Thd brdsh consists of a fiVe-inch length of polyester bristles -held.by atwo-strand, ;coiled-wire stem or,.handle. Each'wire strand is 304 stainless steel, and is approximately 1/8" Vdiameter. The overall length of the stem is approximately 7". The brush was not retrieved, and is considered a loose part.

Evaluation Summray -

Engineering *det6rmined the missing brush will not'cause new accidents or have a'ny :effect:"ithe initiation or'c6nseq uences-of previously evaluated accidents.

One isue was iidentified, the potential for a tube leak in an RHR heat exchanger.

The tube: lek was ý5reviousl*IyeVaiu5ated

-ii the FSAR, and has no consequential effect *on he heat exchanger-function.

T.TeK evaluation concludes that the loose part Wfi[l ndtcausý daniag~et6,he fuel nor ii-mpede any imptortant-to-safety functions of the affected systems andcrmponents.

This activity does not require prior NRC approval.

8.0 10 CFR 72.48 Changes, Tests, and Experiments There were no activities implemented during 2007 that required reporting pursuant to 10 CFR 72.48 requirements.

9.0 Regulatory Commitment Changes (NEI 99-04 Process)

This section reports a change to a regulatory commitment consistent with the information pertaining to Regulatory Commitment Changes (RCC) and is included pursuant to the NEI 99-04 criteria for reporting.

Compliance with NUREG 0612 (RCC-107070-00)

The original commitment description states that prior to transporting an SRV to or from the installed location and passing over the 14" LPCI B injection line, operators will verify or initiate the RHR-A loop of SDC. The commitment is based on a discussion'regarding the possibility of damage to the LPCI return line from a dropped SRV. In compliance with NUREG 0612, the original commitment states:

The [RHR-B] line is protected by steel grating (1.5" deep 3/16" bars spaced 1 1/8" apart) supported on a 4' rectangle of 8" and 14" deep I beams. The RHR line is a 7' radius bend at this location making a direct blow impossible even if the grating were penetrated. This coupled with the existence of an alternate shutdown cooling system (RHR Loop A) which does not pass under the relief valve monorail provide ample assurance that shutdown cooling capability will not be compromised by a potential drop of a heavy load.

Page :14

. :I.

Columbia Generating Station 2007 Annual Operating Report The last sentence has, been revised -to. say.:-

This coupled with the existence of an alternate shutdown cooling system which does not pass under therelief valve monorailprovide,-ample assurance that shutdown cooling capability will not be-compromipsed by a potential.drop.pf a heavy-load.

Energy Northwest has developed an alternative RHR (shutdown cooling) system that uses safety related components. This system uses,.RH.R-,B and.FPC components located outside of containment.to transfer a from thel:SFP

.4hrough the RHR-B h eat exchlanger*.nd into both-the..SFRI.andRPV-cavity.

....Outboard containment,isolation,.valve-RHR-.V-42B, is closed.isolating this cooling

.'system from the LPCI-B line inside containment., CopcuryrentWith this, the FPC system is operating to transferzwyater frqR,,the-.FP through.tqe:,FPC, heat, exchangers and ipto the RPV cavity. This., configuration j,.prqyen!toq provide acceptable shutdown cooling perf'man-ce,..

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