IR 05000237/1992034

Safety Insp Repts 50-237/92-34 & 50-249/92-34 on 921214-930129.Violations Being Considered for Ea.Major Areas Inspected:Followup of Previously Identified Items,Lers,Mod & Changes to Facility & Review of Operational Safety

ML17179A728
Person / Time
Site:	Dresden
Issue date:	02/11/1993
From:	Hiland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML17179A727	List: IR 05000237/1992034 ML17179A726
References
50-237-92-34, 50-249-92-34, NUDOCS 9302230136
Download: ML17179A728 (23)

Text

U.S; NUCLEAR. REGULATORY COMMISSION

REGION III

Report No ~237/92034(DRP); 50-249/92034(DRP)

Docket No ; 50-249 License Nos. DPR-19; DPR-2 Licensee:

Commonwealth Edison Company Opus West III 1400 Opus Place Downers Grove, IL 60515 Facility Name:

Dresd~n Nucle~r Station, Units 2 and 3

..

Inspection At:

Dresden Site, Morri~, Illinois-lnspectiori Conducted:

December 14, 1992 th~ough January 29, 1993 Inspectors:

M. Peck-W. Rogers *

M. Leach A. Stone J... Guzman R. Zuffa; Il1inois_Department of Nuclear Safety Approved By:.*

. f}j 1/4t P. Hilan~

Reactor Projects Secti6ri lB

• Inspection Su~mary

). ~11/ q 3 at'e. * *

Inspection from December 14, 1992. through January 2~. 1993 (Reports N /92034CDRP}: 50-249/92034CDRP)).

Areas Inspected: A special safety inspection conducted by the resident inspectors and the Illinois Department of Nuclear Safety inspector conterning the circumstances *surrounding the degraded containment cooling service water flow identified on April 2, 1992, and the licensee's subsequent corrective actions.* The special inspection included followup on previously identified items; licensee event reports; modifications and changes to the facility;.

• review of operational safety; and events followu Inspection modules used during this inspection were:

37828, 71707, 92700, 92701, and 9370 PDR ADOC~ 0500023

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~

PDR

Results:

Several apparent violations were identifie *

An apparent violation o~ 10 tFR 50.59, with multiple examples.*

. The regulation requires Commission approval prior to making

. changes to the facility. that involv~ an unreviewed saf~ty question (paragraph 7 and 10).

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An apparent violation of 10 CFR 50, Appendix B, Criteria XVI, Corrective Actions, ~ith two examples (paragraph 4 and 8).

• An apparent violation of 10 CFR 50, Appendix B, Criteria Ill, Design Control, with two examples* (paragraph 6 and 9).

• * *.An apparent violation of 10 CFR 50, Appendix B, Criteria XI, Test Control, with two examples (paragraph 8 and 12).

• An apparent violati6n of 10 CFR 50.72/73 reporting requirements with multiple examples (paragraph 11).

Additionally several weaknesses in the licensee'i man~gem~nt control*

syste~ were jdentified. These weaknesses resulted in failure to:

. Ensure the operatirig autho~ity ~akes required NRC notificatio *

Ensure engineering personnel verify assumptions used in contractor prepared analyse * *

Perform adequate safety evaluation *

Ensure adequate ~orrective actions taken ~o repair degraded equipmen *

. ~*- ---~=--.

• DETAILS Pers6ns Contacted

• C. Schroeder, Station Manager

• R. Flahive, Technical Superiritendent

• J. Kotowski, Operations Manager *

T. O'Conner, Assistant Sup~rintendent, Maintenance J, Achterberg, Assistant Superintendent,- Work Planning

• M. Strait, Technical Staff Supervisor *

• J. Shields, Regulatory Assurance Supervisor

. *H. Massin, Enginee.ring Superv.isor

~s. Viehl, Engineering Supervisor

• E: Carrol, Regulatory Assurance

• *A.. O'Antonio, Site Quality Verification

• J. Nash, NSSS Vendo *

• S. Eldridge, Site Engineering

. *J. Kish, Safety Quality Verification

• *P. Piet, Licensing Administr~tion

• T. Schuster, Licensing Superintendent

• T. Gallaher, Staff Engineer

• R. Ralph, Assistant Supervisor

• J. Gates, Assistant Technical Staff.Supervisor

• S. Rhee, Technical Staff

• N. Diariridakis, Technical Staff

~C. kent, Training

• D. Saccommando, Licensing

• R~ Radtke, Site VP Staff

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..

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U.S. Nuclear Regulatory Commission

• B. Cl~yton, Chief, DRP 8rartch 1 *

• P. Hiland, Chief~ Reactor Projects Section 18

• I. Yin, Regional Inspector

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• Den6tes those attending the exit interview* conducted on January 29, 1993. *

The inspectors a 1 so talked with and interviewed seve*r*a 1 other 1 i censee

• employees during the course of the inspectio. *

Background The containment heat re~oval system (CHRS) consisted of two independent train Each train was designed to include:

Two *low pressure coolant injection (LPCI) pumps wifh a train flow of 10,700 gallons per minute (gpm).

Two containment ~ooling service water (CCSW) pumps with a train flow of 7,000 gpm.

.*

-**

One heat exchanger (Hx) with an original duty of 105 million british-thermal units per hour {MBTU/hr) at 95°F river water tempe_ratur The CHRS used CCSW on the secondary side of.the LPCI H T_wo CCSW pumps

{A/B l C/D) were connected to each Hx through com~on pipin The CCSW pumps suet ion source was the intake fore bay {the ultimate.heat*~ ink).

A ~otor operated valve {MOV) maintained a minimum of 20 pounds per square inch~differentfal (psid) acro~s the Hx tubes to ensure n radioactive fluid passed into the environmen Plant tech-nical specificat.ions {TS) limiting condition for operation,s

{LCO) permitted reactor operation for 30 days following the loss of one of the four CCSW pumps and J days following the loss_6f two of the

• four pump Reactor operation was ~ot permitted with less than tw6 CCSW.

pumps available. The TS Surveillance required each pum~ to produce 3,500 gpm flow at a discharge pressure of 180 pounds per square inch~

gage (psig).

. Degraded CCSW Flow Conditfon On April 2~ 1992, operations personnel observed only 5,600 gpm CCSW train flow available on Unit,000.gpm flow was expected-based on operattir training, the updated final safety analysis report {UFSAR)

. design flow~ and Dresden Operating Protedure {DQP) 1500-2, "Torus Water Cooling Mode of Low Pressure Coolant Injection System."* Unit 2 CCSW flow was not tested; however, the licensee assumed the degraded condition existed on both unit *

Licensee's Operability Evaluation On April 4, 1992, the licensee concluded system operability ba$ed on the following:

An evaluation of the pre-blowdown maximum bulk and local

.

suppression pool '{SP) temperatures using the assumptions in the Mark I long term coritainment. program and degraded CCSW flow heat

• removal capabilit An evaluation of the torus attached piping {TAP) hydrodynamic loads and modification~ in ~egard to the higher peak local SP temperatures for the limiting transien *

• The assumption that the limiting design basis accident {OBA) loss of coolant accident {LOCA) containment cooling analysis was bounded by 1 LPCl/l CCSW pump combination (3,500 gpm) CHRS accident mitigation.

. The 1 LPCl/l CCSW pump OBA mitigation assumption contradicted the safety analysis report {SAR) discussions of the OBA containment cooling analysis and the design bases for the LPCI Hx.. The SAR indicated a

• -- ---....---~* - ---- -

.minimum of two CCSW pumps were required {7,000 gpm).

However, the licensee concluded the SAR was in error. This conclusion was based on:

A 1967 plant process diagram {Drawing Number 729E583), supplied by the nuclear steam supply.system {NSSS) vendor. The diagram

provided the.re~ults of a I. LPCI/l CCSW pump DBA LOCA containment heat r~moval analysis. *

TS.Basis 3.5.B, "Containment Cooling Service Water," was

• interpreted to mean the I LPCl/l CCSW pump combination met the minimum cooling requirement *

Emergency diesel generator {EDG) post accident loading was limited to only one~CCSW pump on each bu *

SAR reference~ on electrical systems indicated one CCSW pump may be started and loaded on the EDG within two hours after the DBA

• LOC *

A draft letter "clarifying" the licensing bases provided by the NSSS vendor (reference GE letter J. E. Nash to S. Mintz dated April 6, 1992).

Licensee's Corr~ctive Actions The licensee changed the SAR description of the plant.design, to reflect the degraded flow condition~* A SAR statement that two CCSW pumps were required to provide cooling capacity was changed to one pum The SA change and 10 CFR 50.59 safety evaluation were 6n~site reviewed on April 7, 199 On August 18, 1992, DOP 1500-02 was revised to require operator verification of only 5,600 gpm CCSW train flow during accident cbndition *

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. Degraded Con.tainment Cooling Hx Heat Removal c*apability

• The 1967 plant process diagram *predicted a 180°F SP temperature and use a Hx duty of 84.5 MBTU/hr_ fo~ the limiting containment heat removal case (1 LPCI/l CCSW pump).

The inspe~tors identifi~d the Hx duty value was i~correct. The overall heat transfer coefficient (U) used in the 1 LPCI/l CCSW pump case was the same used in the 2 LPCl/2 CCSW_pump case (based on a log mean temperature difference method evaluation).

The inspectors estimated use of the corr~ct U va]ue would result in a 7 - 13% degradation in heat removal capability. The degraded duty would have resulted in a greater post accident SP temperature than predicted by the process diagra The inspeC:tors communicated the concern to the license~'~ engineering staff on April 6, 199 In response to the inspectors concern, the licensee performed an evaluation (based on a graphical effectiveness solution technique) which confirmed the duty specified in the 1967 process diagram was correc However, after reviewing the evaluation th~ inspectors could not

_,_ *.

validate* the licensee's conclusio The inspectors subsequently

• requested the briginal NSSS vendor's Hx duty calculations for. revi On May* 15, 1992, the inspectors we 7re notified the original duty caltulations were not r~trievable. However, the NSSS vendor re-calculated the 1 LPCl/l CCSW pump mode heat remov~l capability. The new calculation resulted in a 77.Q MBTU/hr dut The Hx manufacturer *

conffrmed the new calculations us*ing proprietary design code The new-duty resulted in a 9% reduction in the heat remova 1 capability from the originil condition The NSSS vendor recovered an unsignedletter (dated January 20, 1969)

.

which described the 1 LPCI/l CCSW pump analysis repr~sented on the 196 process diagram.. The letter indi~ated:

The peak SP temperature, 180°F, would.be reached at 22,000 seconds after the acciden *

-

At 180°F SP.temperature the ~mergency cor~ cooling ~ystem (ECCS)

pumps net positive suttion head available (NPSH.) was

.

approximately equal to the net positive ~uction head required (NPSHr) with little or no margin;

The ECCS pump NPSH. was calculated u~in~ atmbspheric pressure in

• the contain~en *

Failure to identify and take prompt corrective ad ion when notified. of the degraded Hi duty on April 6, 1992, was an apparent violation of 10 CFR 50, Appendix B, Criteria XVI, Corrective Action

(50-237/92034-0la(DRP)}.

Licensee's Operability Evaluation The licensee concluded tcs~ syitem operability based ~n a comparison of *

.the May-Witt decay heat model with a "realistic" decay.heat model

.

{ANSI/ANS 5.1, 1979}.

The realistic model predi~ted 15% le~s decay

• energy at point of peak SP temperature (22~000 *se~onds} than May-Witt~.

Adjusting for the 9% Hx duty degradation, the licensee conclud~d a 6% *

margin existed for post accident CHRS performanc The NSSS vendor indicated strong evidence existed to_conclude that May-

. Witt was used for the original containment heat removal analysi *However, conclusive documentation was.not retrieve.

Ne~ Containment Heat Removal Analysis

• The licensee completed a new DBA LOCA containment heat remov~l evaluation on December 1, 199 The new analysis evaluated the following four cases:

-~--:----, -----*--*-.- --- --** -

Cas~ Configuration

2 LPCl/2 CCSW pumps 1

2 LPCl/2 CCSW pumps2

1 LPCl/l CCSW pump

4

- 1 LPCI/l CCSW pump

_

1 nominal flow rates Peak SP Temperatures 168°F 171°F 180°F 186°F

-_ 2 flow rates adjusted for flow uncertainty Margin to NPSHr 9.3 ft head 13.4 ft head 9.0 ft head 14.0 ft head The 2 LPCI/2 CCSW pumps case Hx duties used.corresponded to the degraded train flow condition The 1 LPCI/l CCSW pump case duties u~ed were reduced (from the original analysis) to r~flect the correcfion of The ANS 5.1 (1979) decay heat m6del, with no uncertainty adder, and

- elevat~d toru~ pressure were also used in the. evaluatio On * __ -

_

December 1, 1992, the licensee completed a second SAR update to include the evaluation results and to further "clarify" the licensing bases. The accompanying saf~ty evaluation concluded no unreviewed safety questioris (USQs) existe.

Inspectors Review of the New Containment Heat Removal Analysis

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The inspettors identified the following co~cerns and di~crep~ncies with the new containment heat remo~al analysis:

Unapproved use of ANS 5.1 (1979) decay heat mode *

Unapproved use of SHEX computer model for containment LOCA respons *

Incorrect assumption~ for net positive suction head calculation *

Incbrrect assumed CCSW initiation tim Unapproved Use of ANS 5;1 (1979) Decay Heat Model ANS 5.1 (1979) decay hea~ model w~s used by the NSSS vendor fo_r the drywell temperature (DWT), drywell pressure (DWP), and SP.temperature responses for the four cases evaluated in the new analysis. _The heat input predicted by ANS 5.1 (1979) was non-conservative when compared.to either:

Branch Technical Position-ASS 9-2, Residual Decay Energy For

_

Light~Water Reactors For Long~Term Cooling, Staridard Review Plan, 9.2.5, Ultimate Heat Sink, or

May-Witt model

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An NRC st~ff position concerning the boiling water reactor (BWR) Power* -

_UPRATE Program -(TAC No. 79384) was issued September 30, 199 Power

• • -.*

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UPRATE was a proposed generic ptogram for increasing.thermal power

.limits~ The staff approved the vendor's proposal, as described in

. Topical Report NEDC-31897P-l, "Generic Guidelines for General Electric Boiling Water React_or Power Uprate" with the exception of the calculati6n. of SP response to LOCA event The Staff Position ~tated:

The model was *not approved for generic use..

Methodology and comp~ter codes specified in the plants SAR should continue to* be* used for the calculations. of containment response to LOC *

A plant specific amendment was required befo~e "more realistic" models could be use *

The ANS 5:1 (197~) decay heit model was used w1thout the additi~n of an

~ntertaintY adde The NRC h~d approved ANS 5.1 (1979), on a plant specific amendment bases, when an uncertainty adder of ~10% was use The licensee did not have~ plant specific ~mendment approving the use of the ANS 5.1 (1979) mode The licensee estimated use of May-Witt would result in an additional 15°F in the peak bulk SP temperat~re Unapproved Use of SHEX Computer Model For Containment LOCA Respons The SHEX computet model ~as also used for the coritain~ent heat response cases evaluated in the new analysi The September 30, 1991, Staff Position stated the SHEX computer code was not approved for the generic use of suppression pool response to LOCA event The posit~on sta~ed a plant specific amendment was requi~ed.. The amendment request ~as tci.

include specific justification (and confirmatory calculations for validation) for its us No ~mendment was app~oved for Dresde Incorrect Net Positive Suction Head Calculations The licensee evaluated LPCI NPSH. for the four OBA cases. Post-accident*

elevated torus pressures (minimum of 4 psi) wer~ used in the

.

i~lculati6ns. This assumption contradicted the bases for TS 3.1~A.c, which restricted the -initial maximum SP temperature to 95° TS 3.7~ ensured containment pressure was not required to maintain adequate NPSH

. for the ECCS pumps for the 2 LPCl/2 CCSW case. Also, Safety Guide 1,

• "Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps" (November 2, 1970), stated the CHRS should be designed ~o that adequate NPSH was provided to system pumps assuming maximum expected temperatures of pump fluids and no increase of containment pressure from that present prior to postulated loss of c66lant accident Use of elevated containment pressure was also inconsistent with the emergency operating procedures (DEOPs).

DEOP-200-1, "Primary Containment Control," directed the. opetating authority to initiate torus

• and drywell sprays before containment pressure reached 9 psi The sprays were to remain in operation until the containment and wet-well pressures were less than 2 psi The calculations assumed a minimum of 4 psi.over pressure;

The licensee did not.evaluate NPSH. bounding Conditions.* NPSH. was calculated only at the pressure and SP temperature* state-points provided

. for the four case~ analyzed. Actual NPSH conditions could be more limitin Increased LPCI flow {at a constant CCSW flow, fr6m the reduced flow state~point condition) decreases NPSH. and ~ncreases NPSHr with a minimum effect on the saturation pressure {temperature) of the SP water. * Also, the calculatioh did not evaluate core spray {CS) NPS The SAR indicated CS NPSH was more limiting than LPCI.

. The NPSH. calculation used NPSHr and suction piping losses from a 1984 letter used for emergency operatirig procedures {EOPs) development. The information provided by that letter was not verified under the Quality Assurance program requirement Failure to evaluate the bounding conditions for NPSH that ECCS pumps would b~ subject to was an apparent yiolation of 10 CFR 50, Appendix B, Criterion III, Oe~ign Control {50-237/92034-02a{ORP}).

..

The NPSH calculation appeared non-conservative by one to two Ft., The LPCI pump NPSH. was presented in "feet of head"_ {Ft) at the elevate torus t~mp~ratures {168°F - 186°F).

However, NPSHr w's determined using cold wate The licensee did not compensate for the density change affect on "Ft of he~d" at the elevated tempe~atures. The difference,

• when crimp~red to psia, ~as proportional to the ratio of the specific volumes at the elevated temperature The failure to include temperature correction of the NPSH. values was considered. unresolved pending further review by the NRC

{Un~esolved Item {237/92034-03{0RP)).

Incorrect Assumed CCSW Initiation Time The CCSW system initiation time assumed in the analysis was inconsistent with operator training and administrative control The analysis assumed the CHRS, and associated Hx, was available for the remo*val of

• energy ~rom the SP at 600 seconds after the OB Plant operating procedures did not specifically address when the CHRS was to be plac~d in ~ervice. The operating authority was trained to initiate the system between 20 and 35 minutes following the OB The inspect6~s estimated the delay_ would result in an additional 3°F to 4°F post OBA peak SP temperatur The inspectors communicated the concern to the licen~e~ rin

. January a*,. 199.

. Safety Significance of Degraded CHRS The loss of ECCS pump NPSH in the p~st-LOCA environment ~ouid potentially challenge the r~maining two fis~ion product _barriets:

• e The fuel cladding would be challenged due to overheating following the loss of CS and LPCI. pump *

The contain~ent would be challenged following failure of CHR *

The ECCS pump seals would be challenged.as the SP v~por preistire approached saturation condition The inspectors e~aluated the ECCS pump net p6sitive* suction head margi~

(NPSHm) using the licensee's containment pressure and SP temperature

• s~ate-point NPSHm was defined-as NPSH. minus NPSH Atmosph~ric pressure in containment (Ct) and the estimated elevated SP temperature conditions, if the original decay heat model was used (an additional 15°F SP te~perature}, were consid~re Net Positive Suction Head Margin Case 1 Case 2 Case.3 Case 4 (Psi a)

(Psi a)

(Psi a)

. (Psia)

ANS 5.1 & Ct over pressure.3.5

• .ANS 5.1 and 14.7 psia Ct pressure

- '.9

- May-Witt and. Ct *over pressure *.8.2 May-Witt and 14.. 7 Ct pressure

-.6

-.7

-*use of the original decay heat model would have eliminated almost all NPSH margin assuming containment over ptessure.. Also, the evaluation concluded inadequate NPSH. when_ atmospheric containment pressure was

. assume ln~pectors Review of Root Cause Based on review of available information; the inspectors concluded the

• .following ca~sal factors contributed to the apparent violations

• identified above:

Failure to verify assumptions used by -contractor personnel

.*

Inadequate. p~oject integration with the design base~

Previous Occurrences A previ6us non~cited violation (50~237/91010-0l(DRP)) 6f 10 CFR 50~

Appendix B, Criterion III, Design Control, was issued fot the failure t ensure adequ~te contractor revie The issue dealt with the use of non-

~onservative parameters and assumptions in vendor calculations associated with a diesel generator cooling water sy~te~. As corrective action, the licensee issued Engineering and Construction (ENC) procedure

.*

_ ***

QE-81, "Review of Assumptions and Judgments for Architects Engineering and Evaluations."

ENC-QE-81 was to assure applicable regulatory requirements were ~ddressed for design evaluations and an ad~quate review of associated assumptions was performe.

.

NRC Review of Cu~rent Li~ensing and Design Bas~s The inspecto~s reviewed the updated final safety analysis report

• (UFSAR); the* final safety analysis report (FSAR); the original and current technical specifications (TS); the original and current TS bases (TSB); and the systematic evaluation prog~a~ (SEP) description of previ6us containment heat removal analyse The purpose of the review was to ascertain the Dresden CHRS licensing and design bases and determine the minimum number of CCSW ~umps required to mitigate OBA event SP OBA LOCA Temperature Response Both the original and current TSB 3.7!A stated bulk SP temperatu~e was expected to rise 50°F, to 145°F, immediately follo~ing the OBA LOCA blowdown.. The drywell temperature (DWT) and drywell pressure (DWP) OBA responsei were shown in SAR Figures 5.2.12 and 5.2.11. *The curves _

provided the long~term (greater than 600 ~econds) containment response for four cases of CHRS operatio The most limiting resporise was for

% containment cooling l~op and one*c6re spray p~mp (case "d")~ Half containment cooling loop was defined as 1 LPCl/2 CCSW pump Ho~ever, the licensee concluded the case "d" curves represerited*the one CCSW pump case represent~d on the 1967 plant process diagram. *This assumption was used in the operability evaluation described in paragraph 3 of this repor *

In the SAR analysis, the SP was heated by the flow exiting from the reactor. The original DWT case "d" curve indicated a drywell temperature of 173°F at the 22, 000 second point. The SAR stated the drywel l temperature was taken to be 5°F hotter than the exiting flo.

Therefore, the SP temperature for case "d" must have bee~ less than 173° The 1967 1 LPCl/l CCSW pump evaluation resulted in a SP *

temperature of 180°F at 12,000 se~ond Comparison of the new containment heat removal analysis DWT and SP temperature data with the original DWT case "d" also confirmed the curve represented two CCSW pump Cu~ve "d" plateau at 177°F between

4,000.and Ia,ooo seconds after the acciden At this point, the new analysis predicted SP temperature lagged DWT by 15°F to 6°F. Also at 22,000 seconds, the new analysis predicted the SP temperature would l~g the DWT, *

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FSAR Section 6.2.3, Heat Exchangers, stated the LPCI Hxs ~ere sized to meet the containment capabilit The duty was det.ermi ned by cal cul at i ng the a~ount of heat which must be rejected from the SP, assuming HPCI *

operation, so that in the. ~~-e~n:_. °,f a LOCA,

~~e ~:e~-~i_n~a*l SP temperature

would not exceed 170° Also FSAR Table 6.2.4 stated the Hx duty design*.

temperature was based on 165° *

SAR Amendment 22 addressed Advisory Committee on Reactor Safeguards concerns related to torus water contamination that may lead to an ECCS pump failure. *One of the concerns addressed the failure of drywell co.at ings at high temperature The licensee's evalUat ion compared the

. failure temperature of the coatings with the maximum torus temperature of 170° *

• SEP Evaluation Report, on Topics VI-2.D and Vl-3, discussed the NRC evaluation of mass energy releases for reactor coolant pipe breaks inside containment. *The peak OBA SP temperature of 168°F was predicte Also, the 11censee's summary of SEP Tbpic V~lO.A, RHR System Heat

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Exchanger Tube Failures, indicated the CHRS maintained the SP temperature below 170°F following a OBA:

Throughout the review, the inspectors did not identify any docketed *

record of, a post OBA SP temperature in excess oJ 170°F. Additionally, the original SAR DWT r~sponse curve "d" was found to be consistent with the SAR text statements that two CCSW pumps were requite The 19S7 I LPCI/l CCSW pump case analysis resulted in a SP temperature of 180° The inspectrirs concluded that the 1 LPCl/l CCSW pump case was not submitted and approved by the NRC as.*part of the Dresden 1 i cens i ng or.

• design base *

Drywell Pressure Response The SAR case "d" DWP response showed containment pressur~ dec~eased

_initially following initiation of the 1 LPCl/2 CCSW pumps.. Pressure

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then slowly increased to the maximum due to decay energy addition to the

• containmen The SAR concluded the energy removal by the I LPCl/2 CCSW *

. pumps and Hx was acceptable because the removal rate exceeded the addition rata from all sources. This resulted in decreasing containment pressur SAR Figure 5.2.11 showed that long term containment pressure,*

greater than 600 seconds, was less th~n 8 psi *

Number of CCSW Pumps Required The-licensee cri~cluded that one CCSW pump satisfied the minimum cooling requirements (as discussed in paragraph 3 of this report). This

.. tonclu~i6n was based, in part, on the licensee's interp~etation of TSB 3. TSB 3.5.B stated:

"Th~ containment cooling sub-system consists of two sets of two:

• service water pumps, one heat exchanger, and two LPCI pump Either set of equipment is capable of performing the containment

.c6oling functio Los~ of one coritainment cooling service water pu~p or 6ne LPCI pump does not setiously jeopardize the containment cooling capability as any two of the remaining three pumps c:an satisfy the containment cooling requirements. Since

there.is some redundancy 1 eft, a 30 day repair period is adequate.".

The licerisee assumed the "~ny two of.the remaining three pumps" referred to the remaining pumps on the CHRS train instead of the CCSW pump

. specifi~ syste Therefo~e. the licensee believed that 1 LPCl/l CCSW p~mp was sufficien TSB 3.5.~ was re~ised*on December 12, 1988, {amendment 107) when ECCS - *

testing requirements. were changed~ The On-site and Off-site review

package indicated the TSB change was to identify the equipment in each containment cooling subsyste The original TSB 3.5.B read, in part:*

"Loss of one containment cooling service water pump does not*

. seriously jeopardize the containment cooling ~apability, as any

• two of the remaining three pumps can satisfy the cooling requirements."

The original JSB 3~~.B clearly confirmed the two CCSW pump requiremen Th~ NRC concluded the acceptability of the CHRS ba~ed on a specifit heat removal capability {duty).

The SER, Section 3.3.5, Primary Containment Cooling System stated:.

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.

HThe containment cooling system consists of two independent and redundant spray cooling loops for post-accident heat removal~

Each loop will pump water fiom the pressure suppression pool

{torus) through individual heat exthanges {which are cooled by the *

service water system) and the spray headers located in the

con:tainment drywel The water spray from the headers removes the heat from the drywell atmosphere and flows py gravity back to the*

toru The heat removal capacity for each heat exchanger is 102 MBTU/hr at a river temperature of 95°F, which is adequate to

• prevent overheating of,the torus water follo~ing a desigri basis accideri We conclude that this ~ystem is acceptable."

Previous NRC CHRS Concerns SEP Evaluation Report on Topic~ VI-2.D and VI-3 discussed an evaluation

• of the OBA LOCA analyses submitted by the licensee. The NRC concluded the analysis results were within design limit In addition to the

• docket review, the NRC performed a confirmatory containment pressure and heat removal analysis using modern assumption The review compared the

. Dresden corifiguration with the criteria used for the licensing of new facilities {General Design Criteria {GDC) 16, Containment Design, GDC 38, Containment Heat Removal, nDC-50, Containment Design Bases and NUREG 800, Standard Review Plan, Section 6.2.1, Containment Functional

Design).

• The *confirm~tory analysis used 102 MBTU/hr LPCI Hx duty and 7,000 gp CCSW flow {2 pumps)~ The NRC requested that the licensee respond within 30.:_day_s_if_th~. as-'built facilit-y differed fromcthe licensing-or des*ign -

basis assumed in the_ asse~sment (December 28, 1981).

The ~RC stat~d t~e -

evaluation would be a basic input to the integrated safety assessment unless -the licensee identtfied changes to reflect the as-built conditions of the facility. Jhe NRC stated the assessment could be revised in the future lf the design was changed or if NRC criteria was

- modifie '

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Unrevi~wed Safety Questions NRC acceptance of the CHRS was based on a duty of 102 MBTU/Hr at a river temperature of 95° Th* heat removal requirements were corr~ctly -

translated into system design criteria which specified the Hx duty of at leas~that. to match the assumpti6n in the-heat removal analysts. The -

CHRS specific function was the* capability of removing 102 MBTU/Hr from-the containment in the post~accident environmen To assure the heat removal capability, 7_,000 gpm CCSW flow was specified as a design criterfa. The validity of the safety analysis assumption of 7,000 gpm CCSW fl ow was ma i n_ta ii'led by TS 3. 5. B, which required a mini mum of two CCSW pumps, at 3500 gpm each,_ available d1Jring reactor operatio The licensee changed the plant.design*, as described in the-SAR, by

• reducing the minimu~*number of CCSW pumps from two to onei and by reducing the CCSW train flow from 7,000 gpm to 5,600 gp The change reduced the margin of safety as defined in-the bases for TS 3.5.B and 3.7. *

The resulting 1 LPCl/l CCSW case contain-ment analysis indicated the long term containment.pressure exceeded 8 psig. This reduc~d the margin of safety as defined in the bases for TS 3. *

The change reduced the Hx capacity below ~he value stated in the SER as a basis for approving the containment cooling syste *

The chang~ reduced the number of CCSW pumps tequired to less than tw This reduced the margin of safety as-defined in the bases for TS-3..

-

_The change reduced tontainment cooling (due to the reduced CCSW flow) to the point containment over pressure was required to demonstrate ECCS pump _NPSH for the 2 LPCl/2-CCSW pump cases. This reduced the margin of safety as defined in the bases for TS 3. 7. \\

'

The change resulted-in the SAR post OBA LOCA containment pressure_

and temperature response curves to be exceede *

_The-change was based on an unapproved comput~r code for the calculation of SP respons~ to LOCA (SHEX) and an unapproved d~cay heat mode This reduced the margin of safety as defined in the bas~s for TS 3. *Failure of the licensee to obtai~ prior NRC approval fbr the SAR changes was an apparent violation of 10 CFR 50.59 (237/92034-04a(DRP.)).

Licensee's Safety Evaluation Program The licensee's 10 CFR 50.59 safety evaluatfonprogram defined the

"margin of safety" for the bases of any technical specification as that margin between the acceptance.limit and the failure.point of a

.

particular piram~ter or componen The licensee's acceptance limit for the new containment heat removal analysis was the design limit for primary containment (62 psig).

The licensee defined the margi~ ~f safety as the margin. between the design limit and failure point.* Th-e failure point was some unknown value where the containment would fail from over pressure (estimated to be about 130 psig).

The licensee's -

program would have allowed the change provided the resultant pressure did not exceed 62 psi The inspectors concluded the-licensee's program for determining a reduction in the ma~gin of safety was inadequat The TSB should b~

used to the m~ximum ~xtent practical, when the margin of safety is -

explicitly defined or addressed therei When the bases do not define

. the margin of safety, the SAR, the SER, and other licensing bases documents should be reviewe *

The margi~ could be implicit rath~~ than explicitly expressed as a numeri"cal value.. Implicit margins are conditions for NRC acceptance, such as for computer codes, methods, industry acceptance practice or penalties. It may be sufficient to determine o~ly the direction of the margin chang If the margin is reduced, the change may involve an US *The margin of safety defined in the bases section of the TS may depend on a parameter other than the process variable The TS.were provided to ensu*re the pl ant _operated in a manner to ensure acceptable levels of protection for the health and safety of the publi The TS ensured that the available equipment and initial conditions meet

. the ass~mptions in the accident analysi The TS were not meant to be all inclusive. They are reserved for thpse matters where the imposition of rigid conditions, limitations upon reactor operation ~as deemed necessary to avoid an abnormal.event or give rise to an immediate threat to public health and safet Previous NRC Concerns Regarding the Licensee's 10 CFR 50.59 Program The NRC held a working meeting in the Region III offices on March 30,.

1992, with the licensee and Nuclear Reactor Regulation (NRR)

conc~rning how SER values should be treated in safety evaluation The meeting was the result of previous NRC concerns associated with the licens~e's

. safety evaluation program, specifically related to how calculation as~umptions were used jn the control room habitability analysi The NRC concluded the change did not constitute a USQ because the licensee failed to update the SAR with the SER (Unresolved Item 90022~02 &

In_s_p~cti_on Reports-91039 and 92005).

.*.

The NRC identi.fied a previous USQ (Violation 50-237/90022-0l(DRP)),

concerning the practice of using a sample pump for containment air sample The modification reduced the margin of safety as defined in the basis of the TS in regard to the maximum allowable primary containment accident leak rat The NRC previously identified two inadequate safety evaluations (Violations 50-237/91016-0l(DRP) and 50/237/90022-0l{DRP)).

In both

• cas~s the licensee failed to consider the.probability of a malfunction of equipment import~nt to safety in a safety evaluation. The cause of both violations was a failure of licensee personnel to recognize _the need to review the SEP commitment Inspectors Review of Root Cause Based on review of available information, the inspectors conclu<;fed the foll~wing causal factors contributed to the apparent violation identified above:

Failure to ~dequately revie~ the licensing bases, including the SEP Topic *

Failure to ver,ify assumptions provided.bY the NSSS Vendo *

Failure t6 understand the definition of the margin ~f safety for the bases of a technical ~petificatio.

CCSW System* Fl ow Performance The Unit 2 CCSW pre::opefational test verified greaterfhan 7,000 gpni train flow based on the punips' d'ischarge pressure and pump curve.. A

• test deficiency was recorded concerning the flow indicator. The Unit 3 Pre-operational test did not verify either the one or two CCSW pump flo *

Based on the review of availabl~ information, the two pump d~graded flow*

condition appeaied to be the result of excessive pipe flow resistance and incre~sed demand.. The following contributed to the flow changes:

Installation of the CCSW submergence protection vaults in the late s. * The modification diverted flo~ to the vault coolers and changed the pipi~g configuratio The TS discharge pressure was reduced from 198 psig to 180 psi *

Potential fouling by mud, silt, arid biological foulin *

The 14 inch Hx discharge piping incorporated a 12 inch motor.

operated valve (1501-3A/B) with a high fr:iction coefficient (Cv).

"".

..

The flow measuring orifices wer~ undersized and caused e~cessive system head loss. All four of the orifices were installed backward *

The licensee did not have any records indicating the CCSW train flow had been verified since initial plant start-up..The licensee did -not verify the train flow on Uriit 2 after the Unit 3 degraded conditio~ was identified in April 199 Failure to incorporate an adequate test program to ensure the CCSW components performed satisfactorily, in accordance with the design requirements, was considered ah apparent violation of 10 CFR 50, Appendix 8, Criterion XI, Te~t Controls

{237/92034-05a (DRP)).

.

Failure of the licensee to take prompt corrective a~tion to correct the CCSW degraded flow conditions was consider~d an apparent violation of

• 10 CFR 50, Appendix B, Criterion XVI, Corrective Action

.i50-Z37/92034~0lb{DRP)).

Prior Opportunity:

The licensee had a reasonable opportunity to identify the flow degradation. Generic Letter {GL) 89~13j "Service Water System Problems

.A'fhctirlg Safety-Related Equipment," alerted. licensees to deg-raded service water flow condition GL 89-13, Item II, discussed a te~t *

program to ensure Hx duties. _ However, the 1 i censee e 1 ected periodic cleanin~ of the LPCI Hxs.rather.than performing a test progra GL 89-13, Item V, required review of operafing and* emergency procedures.*

The licensee review did not identify the degraded flow condition or the inconsistencies in the SA * Emergency_ Diesel Generator Loading The SAR electric description was inconsistent with the accident analysi The ofiginal containment cooling analysis was based on a minimum of two CCSW pump~. The EOG loading table reflected sufficient margin for two CCSW pump operatiori following a OB However, a "note" next to the description of the ~econd CCSW pump stated: "if within

.

capability of the diesel generator." Also, the SAR discussion indicated the operator cou*1 d manua 11 y stop one LPC I pump and start a CCSW pump *

after a period not exceeding two hours.

. The existing EOG 1 oad study eva 1 uated one CCSW pump on the EOG supp 1 i ed busses during OBA LOCA condition DOP 1500-02, "Torus Water Cooling Mode of Low Pressure Coolant Injection System," directed operations personnel to load a second CCSW pump on the safety related bus if sufficient capacity was available. However, Calculation 7317-33-19-3,

"EOG Loading Under OBA Conditions," Revision 7, only reflected one ~CSW

~ump in operatio *

.*

The inspectors identified potential margin for the second CCSW pump to be powered from the EOG on December 10, 199 The licensee confirmed

.17

.. '.

.-

the EDG would support two pumps on January 8, 1993, after an evaluation of the pump starting current~ and running loads. Failure to assure applicable regulatory requirements and the design'bases we~e correctly tranilated into specifications, drawings, procedures, and instructions was considered an apparent violation of 10 CFR 50, Appendix B, Criterion III, Design Control (50-.237/92034-02b (DRP)):

• The loading calculation indicated bus voltages dropped to less than 5.5%

during LPCI pump itart. However, the TS val~e for the undervoltage *

relays was 70% {+/-5%).

The estimated steady state load only provided 0.5% margin to rated capac~ty. These issues will be corisidered unresolved pending a detailed review of the loading calculation

{Unresolved Item 237/92034-06 (DR~. 10. * LPCI Hx Tube Replacement Begin.ning in 1989, the 70-30 Cu-Ni LPCI Hx tubes were replaced with AL-6X (stainl~ss steel) following failur Less than 6% of the tubes have been* replace The modification safety evaluation concluded the

• - change did not constitute a USQ.. The SAR was changed to r~flect

.replacement of all the tubes~ The material change-out reduced the Hx duty from 105 MBTUs/hr to 95 MBTUs/hr assuming 7,000 gpm CCSW flow.*

• The licensee performed a SP temperature response analysis to model a small break LOCA {isolation condenser steam line break) with manual depressurization a.nd one CHRS train avai.lable (2 LPCl/2 CCSW pumps}.

The safety evaluation indicated the ~vent yielded th~ highest bulk pool* SP tempe~atures amorig those cases analyzed in the Mark I Lorig-Term Progra. . The licensee used a non-approved decay heat*model in the analysi The model was a derivation of dec*ay heat based on ANS 5.1 (1979).

The derivation employed a low 183.6 MEV/fission value and a 2% uncertainty adder.. The derivation was non-conservative when compared to either:

Branch T~chnical Position ASB 9-2*

May-Witt Neither the Hx tube replacement safety evaluation or the analysis addressed the modifications effect on the following:

• *

The reduction of CHRS capatity in the OBA LOCA analysi * * The magnitude or the -consequence of the increased OBA cont a foment pressure and temperature ~~sporise due to the reduction in Hx dut * The effe~t of higher OBA SP temperatu~es on ECCS*pump NPSH,. piping, or seal The SAR change indi~ated the Hx duty was reduced below the SER acceptance value for the CHR The failure to perform a bounding analysis and adequate review was considered an apparent violation o _10 CFR 50.59 (50-237/92034~04b(DRP)). The Mark I long~Term Program analysis took credit for the avail~bility. of offsite power and a peak local temperature limit of 205° The UFSAR, Section 5.2.3.9;27, "Plant Unique Analysis (PUA) Results," stated all of the applicable Mark 1 criteria were me However, Safety Evaluation Report, "Maik 1 Containment Long-Term Program," NUREG-0661, Supplement 1, stated the local SP temperature shall not exceed 200°F and NUREG-0783, "Suppression Pool T~mperature.limits fbr BWR Containments," required that off-site power be assumed not available (except for feed

• water pumps).

The Dresden specific SER (September 18, 1985) did not indicate NRC approval for the exceptions. This is~ue was considered unresolved pending further NRC ~eview of the PUA (Unresolved Item 50-237/92034-07(DRP)). . 1 Reporting Requirements On April.2, 1992, operations personnel identified significant degradation *of Unit 3 CCSW flow as discussed in paragraph 3 of this

• report. The licensee assumed the degr~ded condition also occurred on Unit Unit 2 was operating and Unit 3 was in refuel mode at the time of discovery.* 10 CFR 50.72 (b)(2) required the NRC be notified within

. four hour~ of occ~rrence of any event found when the reacto~ is . shutdown, that, had it been found when the reactor was in operation

• would have resulted in a principle safety barrier beirig seriously degraded o~ in an unanalyzed condition that ~itjnificantly compromised plant safety. For the operating uhit, 10 CFR 50.72 re~uired the NRC be

~otified within one hour of the occurrence of any event or condition .th~t resulted in a condition outside the design bases of the plan Also, 10 CFR 50.73 (a)(2)(ii)(B) required the licensee to submit a . licen~ee event report (LER) for any condition that resulted in the. plant being in a condition outside of the design bases.. The failure to make the required NRC notifications ~as considered an apparent violation of 10 CFR 50.72 and 50.73 (50-237/92034~08a(DRP)); On May 14, 1992, ~ith Unit 2 operating. and Unit 3 shutdown, the licensee was informed the LPCI Hx duty was degraded 9% from what was believed to have been *used in the limiting case accident analysi Based on the information available, this was a condition outside the de~ign bases of the plant.. The licensee did not initiate a condition adverse to quality report (CAQR), report the event to the NRC within one hour of discovery, or submit*a LER within 30 days. This was* considered an apparent

violation.of 10 CFR 50.72 and 50.73 (50-237/92034-08b(DRP)). On December 15, 1992, with Unit 3 operating, the licensee was informed the decay heat model and computer metho~ used in the limiting CHRS . accident analysis was non-conservative and un-approved for use. This. . was a condition outside the design bases of the plant. The licensee did

• not_ lnJ_tja_te a CAQR, report the event wi thtn one hour of discovery to

- *r*-----*----i---~.-

the NRC, or submitted a LER within 30 day This was considered an apparent violation of 10 CFR 5b.72 and 50.73 (50-237/92034-0Bc(DRP)). On January 8_, 1993, with.both units operating, the 1 icensee was informed of a 20 minute difference bet~een the assumed CHRS initiation time uied

• in.the accident analysis and the CCSW starting time expected from

operator training. This was a condition outside the design bas~s of the* plant and not covered by the plants operating or emergency procedure The licehs~e did not initiate a CAQR or report the event within ohe hour of discovery to the NR This was also considered an apparent violation of 10 CFR 50.72. (50-237/92034-0Bd(DRP)).. 10 CFR Pa~t 21 required, in part, that each*entity subject to the regulation of this part, adopt appropriate procedu~es to provide for evaluating deviations. A deviation was defined as a depa~ture from the * technical requirements of a procur~ment documen A Part -21 basic component included safety related design, analysis, and consulting service The *licensee determined the following non-compl hnces did not require a Part 21 dev~ation evaluation: -

Discovery of the contractor sup~lied degraded LPCI Hx d~ty

• .(May 13, -1992)

.

. Discovery the decay heat model and computer method used in a contractor supplied limiting CHRS accident analysis was non-. conservative arid uri-approved for use (December 15, 1992),* .

. . .

• This i~sue ~as considered unresol~ed pending NRC review of the
• procurement documentation ass6ciated with both activities (Unresolved Item 50-237/92034-09(DRP)).,

. Previous NRC Reporting Concerns Within the p~st two year~, five violations with numerous examples were cited for the failure to meet lO'CFR 50.7l and 10 CFR 21 reportihg. requirements. Violation 237/91016-03 was issu~d for the failure to mak a 50.72 report on January 16,. 1991, when it ~as known that the material

toughness for the reactor studs were o~tside FSAR allpwabl The licensee incorrectly concluded the condition was not a significant degradation. Violation 237/90027-06 was issued for the failure to make .50~72 feport following an ESF actuation on December a~ 199 Corrective actions were inadequate and result~d in anothe~ missed notification in July 199 Violation 237/91022-10 was cited for inadequate corrective actions. The corrective actions to violation 91022-10 p*roved to be

• inadequate also as two additional ESF actuations were not reported in March and April 1992. Violation 92009~05c was cited for the inadequate corrective action Violation 237/92009-02 was cited for an inadequate 10 CFR 21 screening procedure which failed to reco_gnize.consulting services discrepancies, resulting in a defect, as reportable. *The licensee failed to report a

.. defect associated with the VOTES progra The ~rocedure was revised to intlude more specifi~ guidanc In addition, a letter t6 Mr. Cordell Reed, Se~ior Vice President CECo., from Mr. Edward -Greenman, Director, Division of Reactor Projects; Region 111, dated October 4, 1991, clarified the NRC position. The letter stated that use of engineering judgment differed signihcantly between reportability and op~rability determinations. Reportability determinations needed to consider short and. long term operability, * generic implicatio~s, and the importance of the com~onents. To accomplish this, sufficient info~mation for a correct reportability det~rmination was required for the licensed *operations staf Operability determinations shall be prompt commensurate with the.* potential safety si~nificance of the issu * . .

12~ CCSW Intertie t6 the Main Control Room Habitability Ref~iqeration Unit CCSW provided saiety related cool~ng t~ th* only control room emergency heating, ventilation and air conditioning {HVAC) air handling. unit* {AHU).

The normal emergency HVAC cooling source was the non-safety related service water system {SWS).

An interconnecting 2%" branch line allowed any of the four Unit 2 CCSW pumps to supply cooling water to the emergency HVAC system by use of a number of manual valves. and one air op~rated supply valv Upon loss of instrument air the SWS valve failed

• Closed while the CCSW supply valve failed op~ Probl~m Occurrence During the HVAC system design, in 1982, the licensee's c6ntractor indicated a CCSW pump criuld probably deliver the 120 gpm to the control room air conditioning system with a negligible decrease of flow to the LPCI Hx Modification Ml2-2/3~82-l installed the new HVAC system including the CCSW branch line in 1984.. - The post modification test, completed on January 3,- 1985, acceptance criteria was based exclusively upoh receivihg the minimum flow {120 gpm) through the HVAC's air handling unit. Testing did not evaluate the effect of sy'stem interactions ori CCS Problem Identification
• In October i992 the Illinois Department of Nuclear Safety inspector

questioned the effect of the HVAC branch line on CCSW flow performanc A CAQR was generated and on October 28, 1992, the licensee's evaluation concluded the CCSW system was operabl The licehsee estimated a 3 psid drop at the CCSW pump disch~rge due to the HVAC branch line. However, testing completed on November 18, 1992, reflected much larger pressure

• • drops of 4 to 11 psi The B and C pumps were dee l ared inoperable s i nee discharge pressure was only 175 and 177.5 psig respectively. After flow balancing the vault coolers and the HVAC line, the required discharge pressure was achieved and the pumps declared operable..

... ~*

Problem Consequences The inspectors revi~wed historical surveillance tes~ data taken b~twe~n .1990 and 1992, and noted several instances where CCSW pump performance was

• near the.limit for *required pressure and flo After subtracting the pressure drop (4 to 11 psi) caused by the HVAC branch line~ the TS requirements of 3500 tjpm at 180 psi would not have been me Although the CCSW system was degraded by the reduced discharge pressure the safety significant attributes, pump discharge flow and Hx. pressure drop, were itill me The 180. psi assured a 20 psid across the LPCI Hx tube The LPCI system discharge pressure was on the order of 110 ps Therefore, the 20 psid was still maintaine *

Failure to assure the CCSW test surveil 1 ance * demonstrated the system performed satisfactorily, was an apparent* violation of.10 CFR 50, - Appendix B, Criterion XI; Test Control.{50-237/92034~05b(DRP}).

Inspectors Review of Root Cause Based on review of available information, the inspectors concluded the following causal factors contributed to the apparent violations identified above:

The original hydraulic evaluation of.the branch line.failed to quantify the CCSW pressure dro Post modification testing did not validate_ the engineering assumptions ~sed in accepting the CCSW supply to the HVA *

The periodic surveillance tests on CCSW pumps were inadequate to* ascertain the true performance capability of the ccsw system durin i d~sign basis event. *

. The safety evaluation performed for the modification *failed to _ identify the reduction of the margin to safety provided by the bases-. for TS 3/4.5.B~ - Potential for Licensee ldentific~tion df.the Problem The licensee had a reasonable opportunity to identify the proble In 1988 the NRC issued Generic* Letter (GL) 88-14, "Instrument Air Supply System Problems Affecting Safety~Related Equipment."

GL 88-14 required verification that, following a loss of the instrument air system, safety-related equipment would perform as intende The internal review and response to t.he NRC. on Nov.ember 7, 1990, did not detect the proble Had a more thorough. evaluation of the consequences of failing "open 11 the safety relate~ HVAC supply valve and closure pf the non-safety relJted supply valve been performed, the consequences on CCSW could have been identifie. Information Meetings On January 15, 1993, a working lev~l meeting was held at Dresden Station to discuss the safety signifitance and complianc~ issues concerning the degraded CCSW syste At that meeting the licensee presented the safety evaluation philosophy as discussed in paragraph 7 of this repor On January 27, 1993, a second information meeting was-: held at the NRC R~gion III office to discuss ECCS pump NPSH calculations an limitation * 1 Licensee Event Reports Followup (92700)

• (Clcised) LER 237/92038 ~nd Revi~ion 1, Containment Cooling Servic~ Water found Outside Technical Specification Limits due to an Inadequate Systems Interaction Analysi.

Licensee Action on Previously Identified Items (92701) . . (Closed) Unresolved Item 237/92005-06(DRP), Previous unre*solved item concer~ing the degraded CCSW train flow discussed in parag~a~hs 2, 3~ 4~ 5, and 6 of this repor * 1 Unresolved Items Unresolved items are matters ~bout which more information is ~equired 'in order to ascertain wh~ther they are acceptable items~ violations, or deviat~ons. Unresolved items disclosed during the inspection are discussed in Paragraphs 6, 9, 10, and 1. . 17~ E~it Interview The inspectors met with licensee representatives (denoted in Paragraph 1) during the inspecti6n period and at the conclusi~n of the inspection period on January 29, 199 The inspectors summarized the scope and results of the inspection and discussed the likely content of this inspection repor The licensee acknowledged the infrir~ation and- * did not indicate that any of the information disclosed during the inspection.could be considered proprietary in nature.* 23 }}