ML20134E963
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{{#Wiki_filter:'<:6W 4 JA =Y I From: Betty T. Summers (BTS)~ To HEK Dates Tuesday, March 8, 1994 3:52 pm subject: The latest on Vogtle There are six documents, plus the'meno which is named vogtlel.jrg. All the others are various pieces of the Vogtle Pkg. Files g:\\oecases\\vogpaper.r8, g:\\oecases\\vogcover.r10, g:\\oecases\\vognovcp.r5, g:\\oecases\\vogdfil.r6, g:\\oocases\\vogdfi2.r6, g:\\oacases\\vogdfi3.r5, g:\\vogtlel.jrg i i Ynd uk & tk4 0f6 : Y!O No dt. C OW. /Y e#,,W)o/\\ / 1 /,. l / , W///.' /fo inictmatica in this record was deleted in accordance with the freedom of Information I' Act, exemptions d - FDIA- ?!- $N { ,M O 9611040202 960827 PDR F0EA y,,KOHN95-211 PDR
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g 101 MARIETTA STREET, N.W. f ATLANTA. GEORGI A 30223 j %.....+ ij MEMORANDUM FOR: William T. Russell, Director j Office of Nuclear Reactor Regulation l Stewart D. Ebneter, Regional Administrator 1 Region II l i Karen Cyr, Deputy General Counsel for Hearings, Enforcement, & Administration FROM: James Lieberman, Director I Office of Enforcement 1 i
SUBJECT:
PROPOSED ENFORCEMENT ACTION - VOGTLE On February 23, 1994, I distributed the first draft of a proposed j enforcement action for Georgia Power Company's (GPC) submission I of inaccurate and incomplete information on the Vogtle diesel 6-j 'we ask that you submit comments to OE by 1 March 10, 1994 and participate in a meeting to discuss and j finally resolve comments on March 14, 1994 at 12:30 pm. l James Lieberman, Director Office of Enforcement i
Enclosures:
As Stated i l cc: J. Taylor, EDO l J. Milhoan, DEDR l F. Miraglia, NRR l B. Hayes, OI ~ L. Chandler, OGC l J. Goldberg, OGC l D. Matthews, NRR (5) I
l* c,4# ',#24,8 UNITED STATES NUCLEAR REGULATORY COMMISSION ] .? REGION 11 l*$ g-oI 101 MARIETTA STREET, N.W. ATLANTA, GEORGI A 30323 l 1 raan, OE %9 y, OE
- O y File i
EA File l j 1 l o s 1 l 1 i 4 i f 1 4 4 i 1 l t i i 4 i e DD:OE D:OE JGray JLieberman 03/ /94 03/ /94 Doc Name: Ot\\VOGTLE1.JRG i i
e M N PRKDECIEIDIOLI, INFORMATION NOT POR evt.ma'eE-WITIOUT TER APPROYAL'OP TER 1 DISC'idR70E 4 xU Rev. 8: V0GPAPER.R8 3/8/94 March XX, 1994 SECY-94-XII IQB The ce=niaeioners ZBQli James M. Taylor Executive Director for Operations
SUBJECT:
PROPOSED ENFORCEMENT ACTION AGAINST GEORGIA POWER COMPANY, VOGTLE ELECTRIC GENERATING PLANT (EA 93-304, EA 94-036, EA 94-037, and EA 94-052) P_URPOSE: To consult with the cr-miselon r ardi uance of a Notice of Violation and Demands for Information to the Georgia Power Company ( PC).
- Commission is required because BACKGROUND:
4 On March 20, 1990, during a refueling outage at Vogtle Electric Generating Plant (VEGP) Unit 1, GPC declared a Site Area Emergency (SAE) when offeite power was lost concurrent with the failure of the only Unit 1 Diesel Generator (DG) that was available (lA). The other Unit 1 DG (lB) w 9 unavailable due to maintenance activities. The H3C immediately responded to the SAE at the VEGP site with an Augmented Inspection Team (AIT) which was subsequently upgraded to an Incident l Investigation Team (IIT) on March 23, 1990. j On March 23, 1990, the NRC issued a Confirmat Action Letter (CAL) to GPC that, among other things, confirmed that GPC had agreed not to return VEGP Unit 1 to criticality until the Regional Administrator was satisfied that e t
The Commissioners. appropriate corrective actions had been taken, and that the plant coul'd safely return to power operations. On April 9, 1990, GPC made a presentation to the NRC in the Region II offices in support of GPC's request to return VIGP Unit 1 to power operations. As part of this presentation, GPC provided information on DG starts in response to a specific NRC request that GPC address DG reliability in its April 9 presentation. GPC submitted a written summary of Ats April 9 presentation in an April 9, 1990 letter, "Vogtle Electric Generating Plant Confirmation of Action Letter." The NRC formally granted permission for VEGP Unit 1 to return to criticality and resume power operations on April 12, 1990. On April 19, 1990, pursuant to 10 CFR 50.73, GPC submitted Licensee Event Report (LER) 50-424/90-06, " Loss of Offsite Power Leads to Site Area Emergency." On June 29, 1990, GPC submitted a revised LER, 50-424/90-06-01. The purpose of the submittal was to clarify information related to successful DG starts that were discussed in the April 9, 1990 letter and the April 19, 1990 LER, and to update the status of corrective actions in the original LER. i \\ From August 6 through August 17, 1990, the NRC conducted a Special Team i Inspectics (STI) at VEGP, as a result of NRC concerns about, and allegations related to, VEGP operational activities. This inspection examined the technical validity and safety significance of the allegations, but did not l investigate alleged wrongdoing. The Special Team informed CPC that the June 29, 1990 submittal failed to address the April 9, 1990 data and requested that GPC clarify DG starts reported on Abril 9, 1990. On August 30, 1990, GPC submitted a letter, " Clarification of Response to confirmation of Action Letter." The purpose of the submittal was to clarify
- l the diesel start information that was addressed in the April 9,1990 submittal.
On December 17, 1993, an investigation of licensed activities was completed by the NRC's Office of Investigations (01). The investigation was initiated in response to allegations received in June 1990 by NRC Region II asserting, in part, that material falso statements were made to the NRC by senior licensee officials regarding the reliability of the Dos at VEGP as reflected in the series of communications on the issue described above. The OI Report of l Investigation (Case No. 2-90-020R) is enclosed (Enclosure 1). Because of the ~ nature of CI's preliminary conclusions, OI discussed the matter with the Department of Justice (DOJ) on January 9, 1992. By memorandum dated April 12, 1993, DOJ notified the NRC that it was closing its criminal investigation of the matter and recommended that the NRC continue its administrative proceeding. DOJ also advised the NRC to contact DOJ in the' event subsequent NRC investigation identified additional evidence of criminal activity. OI discussed the final results of its investigation with DOJ on December 16, 1993, and DOJ verbally declined criminal prosecution of the matter. 4
1 i f i The Commissioners. September 16, 1993, composed of representatives from the Office of i Enforcement, Region II, the office of Nuclear Reactor Regulation, and the Office of General Counsel to conduct a detailed review of the evidence I collected by OI on the allegations. The Vogtle Coordinating Group (Group) was also tasked with identifying any violations and developing a detailed analysis of the evidence in support of its conclusions. l In addition to this enforcement proceeding, there is an ongoing Atomic Safety and Licensing Board.(ASLB) proceeding considerin the transfer of the i operating license from GPC to Southern Nuclear. l f l vnas DISCUSSION: j I j The OI investigation concluded that evidence uncovered by OI supports a finding of deliberate failures on the part of GPC officials to provide the NRC with information that is complete and accurate in all material respects. OI concluded thats j i j
- (1) the VEGP General Manager (George Bockhold, Jr.) deliberately presented incomplete and inaccurate information regarding the testing of the VEGP i
Unit 1 Dos during an oral presentation to the NRC on April 9, 1990, i (2) GPC submitted inaccurate and incomplete information regarding DG test results in a letter to NRC dated April 9, 1990, as a result of deliberate actions by Mr. Bockhold, } l (3) GPC submitted inaccurate and incomplete information regarding DG air i quality in the April 9 letter to the NRC, as a result of deliberate l actions by Mr. Bockhold, i i (4) the Senior Vice President - Nuclear Operations (George W. Hairston, i l III), with, at a minimum, careless disregard, submitted a false statement of diesel test results to the NRC in Licensee Event Report l (LER) No. 90-006, dated April 19, 1990, as a direct result of deliberate l actions by a group of senior managers including Mr. Hairston, the Vice President - Vogtle Project (C. Kenneth McCoy), the Corporate ceneral l Manger of Plant Support (William B. Shipman), and Mr. Bockhold, (5) Mr. Hairston, with, at a minimum, careless disregard, submitted a falso statement to NRC in the letter of transmittal of a revision to LER 90-C06, dated June 29, 1990, i i l I I 2 licensec organ 6danni charts are included in Enclosure 2. l l l
The comunissioners. (6) Mr. McCoy, with, at a minimum, careless disregard, submitted both a falso statement and a misleading statement in the GPC clarification of confirmation of Action response letter to NRC dated August 30, '1990, and I (7) GPC provided inaccurate information in its response to a 10 CFR 2.206 Petition, dated April 1, 1991. OI could not conclude that these actions were deliberato. j OI also concluded from the combination of the above findings, and the overall review of numerous audio tapan recordings of internal GPC conversations rgarding their canications with the NRC on a range of issues, that, at least in the March-August 1990 time frame, there was evidence of a closed, deceptive, adversarial attitude toward NRC on the part of GPC senior management. ) l i i 4 l i i ll 0 0 4 i
l l ? The Ccnuaissioners. 4 4 Finally, the Group reviewed numerous audio tapes and other evidentiary materials associated with DG testina during tho' March-August 1990 time frame. i il re 4 g# a 'f 6 I f 0 g l i I 4 i a ama 1 e sP 1 a r 4 5 e 4 y
The commissioners
- EQII: This paper and its issues should not be publicly disclosed because the matter involves sensitive as well as predecisional enforcement issues.
James M. Taylor Executive Director for Operations Enclosures 1. OI Report 2-90-020R 2. Licensee organization charts 3. Vogtle coordinating Group Analysis 4. Notice of Violation @ and Demands for Information i 1 e l i i i I 1 1 1 ~
DRAFT PREDE SIOMEL ORMATION 'NOTTOR4ELERS WI OU'i THE PN FpI Rev. 10: VOGCOVER.R10 3/8/94 i Docket No. 50-424 License No. NPF-68 EA 93-304, EA 94-036, EA 94-037, and EA 94-052 Georgia Power company ATTN: Mr. H. Allen Franklin President and Chief Executive Officer Post Office Box 1295 Birmingham,. Alabama 35201 1
SUBJECT:
NOTICE TION ANd D S FOR INFORMATION (NRC OFFICE OF INVESTIG ONS REPORT NO. 2-90-020 AND NRC INSPECTION REPORT NO. 50-424,425/90-19, SUPPLEMENT 1) This refers to the investig0 tion conducted by the Nuclear , Regulatory Commission's Office of Investigations (OI) at Georgia 3
- Power Company's (GPC) Vogtle Electric Generating Plant (VEGP) 4 which was completed on Decembar 17, 1993. 'The investigation was j
initiated as a result of information received in June 1990 by Region II alleging, in part, that material false statements were made to the NRC by senior Officials of GPC regarding the j reliability of the Diesel Generators (DGs). The pertinent events i involved in this matter are described below. On March 20, 1990, during a refueling outage at VEGP Unit 1, GPC 1 declared a Site Area Emergency (SAE) when offsite power was lost concurrent with the failure of the only Unit 1 DG that was available (1A). The other Unit 1 DG (1B) was unavailable due to 1 maintenance activities. The NRC immediately responded to the SAE at the VEGP site with an Augmented Inspection Team (AIT). The NRC effort was upgraded to an Incident Investigation Team (IIT) on March 23, 1990. The IIT 1 was composed of NRC Headquarters technical staff and industry personnel. The results of this investigation are documented in 1 NUREG-1410, " Loss of Vital AC Power and the Residual Heat Removal System During Mid-Loop Operations at Vogtle Unit 1 on March 20, 1990." On March 23, 1990, the NRC issued a Confirmation of Action Letter (CAL) to GPC that, among other things, confirmed'that GPC had agreed not to return VEGP Unit 1 to criticality until the Regional Administrator was satisfied that appropriate corrective actions had been taken, and that the plant could safely return to power operations.
4 t l-Georgia Power Company < On April 9, 1990, GPC made a presentation to the NRC in th'a j Region II offices in support of GPC's request to return VEGP Unit 1 to power operations. As part of this presentation, GPC provided information on DG starts in response to a specific NRC i ] request that GPC address DG reliability in its April 9 presentation. GPC submitted a written summary of its April 9 presentation in an April 9, 1990 letter, "Vogtle Electric Generating Plant Confirmation of Action Letter." l On April 12, 1990, the NRC formally granted permission for VEGP Unit 1 to return to criticality and resume power operations. j On April 19, 1990, pursuant to 10 CFR 50.73, GPC submitted i Licensee Event Report (LER) 50-424/90-06, " Loss of Offsite Power j Leads to Site Area Emergency." On June 29, 1990, GPC submitted.a revised LER, 50-424/90-06-01. The purpose of the submittal was to clarify information related to successful DG starts that were discussed in the April 9, 1990 l letter and the April 19, 1990 LER, and to update the status of corrective actions in the original LER. 4 From August 6 through August 17, 1990, the NRC conducted a Special Team Inspection at VEGP, as a result of NRC concerns about, and allegations related to, VEGP operational activities. l This inspection examined the technical validity and safety l significance of the allegations, but did not investigate alleged l wrongdoing. The Special Team informed GPC that the June 29, 1990 4 submittal failed to address the April 9, 1990 data and requested that GPC clarify DG starts reported on April 9, 1990. Results of i this inspection are documented, in part, in NRC Inspection Report i No. 50-424,425/90-19, Supplement 1, dated November 1, 1991. 1 I On August 30, 1990, GPC submitted a letter, " Clarification of l Response to Confirmation of Action Letter." The purpose of the I submittal was to clarify the diesel start information that was addressed in the April 9, 1990 submittal. The NRC has carefully reviewed the evidence associated with these l events, submittals, and representations to the NRC. i Specifically, the NRC reviewed information gathered as,part of j the OI investigation, information gathered during the IIT, NUREG-i 1410, Supplement 1 of NRC Inspection Report 90-19, discovery j responses in the Vogtle operating license amendment proceeding l (Docket,Nos. 50-424 OLA-50-425 OLA-3 and other related orb f i
Georgia Power Company N i 1 4 I 1 l The VEGP General Manager was personally involved in the preparation of the data regarding l the DG reliability and tasked the Unit Superintendent with j collecti en r of saf starts for the 1A and 1B DGs. I i i In fact, the VEGP General Manager stated no criteria for successful starts, a term not l fully defined, when he dire 6ted the Unit Superintendent to i j gather successful DG starts. The Unit Superintendent l collected DG start data from ntrol Room Log and the l Shift rv l .and orally conveyed 4 l totals to t VEGP General Manager for the 1A and 1B l di s. l Information was then presented to the NRC in an April 9, 1990 oral presentation by the VEGP General Manager and in an April 9, 1990 letter that since March 20, 1990, i there were 18 and 19 successful consecutive starts on the LA j and 1B DGs, respectively, without problems or failures. 1lP c l reported in the presentation and letter included three j starts with problems that occurred during DG j overhaul / maintenance activities (a high lube oil temperature trip on March 22, 1990; a low jacket water pressure / turbo l lube oil pressure low trip on March 23, 1990; and a failure i to trip on a high jacket water temperature alarm occurring l on March 24, 1990). The correct number of consecutive j successful starts was 12 for the 1B DG--a number 1 i i
(. l I f j, Georgia Power Company i I j less than that reported by GPC to the NBC on j April 9, 1990. I l J l I The air for starting'a DG and operating i i. truments and controls is derived from the starting l air system. The starting air system contains dryers j designed to maintai sture content ew int) at secce le levels. l I i A review of l maintenance records and deficiency cards associated with j Unit 1 would have revealed that high dew points were also i attributable to system air dryers occasionally being out of j service for extended periods and to system repressurization j following maintenance, as documented in NRC Inspection Report No. 50-474 425/90-19, Su lezent 1, dated November 1, l J l i, 4 l l ~ l I LER 90-006, submitted to the NRC on April 19, 1990, was based, in rt, o ation resented to the on A ril 9 During the preparation of the LER, the Acting VEGP Assistant General
Georgia Power Company Manager - Plant Support questioned the accuracy of tha April 9, 1990 letter given that there were trips o B DG after March 20,.1990. l l~ dra , the General Manager, Technical Support Manager ater di cussions regarding the and Acting VEGP Assistant General Manager - Plant Support acknowledged that they could not identify the specific DG start that represented the starting point for the count presented to the NRC, i.e., the first start following j completion of the CTP. There were also different 1 interpretations about what testing the term CTP encompassed. The General Manager - Plant Support (Vogtle Project), the j VEGP Technical Support Manager, and the Acting VEGP i Assistant General Manager - Plant Support were aware that j the VEGP General Manager had earlier stated that his April 9 count began after instrument recalibration. The Acting VEGP Assistant General Manager - Plant Support statei that his understanding of the CTP was that it would be a teet program to t causes a restore bili ct, the Un t { Superintendent who colle ed the original April 9th data 4 advised the Acting VEGP Assistant Gsnaral Manager - Plant support and the VEGP Technical Suppod*. Mr. nager that he started his counts on March rio a the time when a CTP could have been completed. l l .the 1A an IB DG start counts reported on l April 19, 1990 overstated the actual counts by including j starts that were part of the test program. the s--the. failure of which was the very saue caused an extended shutdown. GPC waa aware of the NRC's interest in the DGs, in that the NRC spec cally asked GPC to address DG reli y as rt st&rt tation { for April 9, 1990. i Y g g g t;."N N
Georgia Power Company, ) information was available when the counting errors were i made, and (3) the erroneous. counts resulted from rsonnel j eve i 1 i 1 1 1 J i 1 i The Vice President - ogtle Project and the or Vice President - i Nuclear Operations were actively involved in the preparation of the June 29 cover letter, The VEGP General Manager and Vice President - Vogtle Project reviewed, and the Senior Vice President - Nuclear Operations signed, the June 29 { cover letter which stated that its purpose was, in part, to clarif formation provided to the NRC on April 9. i l I i } 90 ter. The 1 tter i stated that errors in the April 9 letter and l presentation and the April 19 LER were caused, in part, by confusion in etion betwee asful start and a valid test. i 1
I Georgia Power Company i During the August 29, 1990 Plant Review Board meeting, the VEGP Manager - Technical Support questioned if the Unit Superintendent (the individual who originally j collected the DG start data) was confused in the distinction between a successful start and.a valid test. The VEGP General Manager admitted that the Unit Superintendent was not confused about the distinction when he collected the j data which was used to prepare the April 9 letter, but l stated that the sentence was not in error because other people were confused. The VEGP General Manager acknowledged that there was confusion raong individuals after April 9, j but admitted that the Unit Superintendent was not co ] when he developed the information. j i i u The August 30 letter states that the e or in e Ap etter l and presentation and the April 19 LER were caused, in part, l by an error made th individual who a count l of j While GPC undertook e forts o correct April 19 LER, t narrowly focused only on that submittal. For example, GPC conducted an audit, the scope of which was limited to review of DG records, in an attempt to correct the start count reported in the April 19 LER. Furthermore, in its June 29 submittal, while GPC, referred to l both the April 9 letter and the April 19 LER, it attempted to explain only the reasons for the error in the April 19 LER. The Senior Vice President - Nuclear Operations and the Vice President - Vogtle Project were directly involved in j the deve t of the June 29 r I j ' Subsequently, i reques a a ddressi l il 9 letter f
t Georgia Power Company - The Vice President - Vogtle Project committed durincj the August 17 meeting with the NRC special inspection team to provide cla ication to the NRC re rding the A letter. GPC forwar a itt regarding the April 9 etter on August 30 that was drafted at corporate headquarters under the direction of the Vice President - i Vogtle Project, without an assessment of the actions of the VEGP General Manager and the Unit Superintendent who i developed erroneous information for the April 9 letter. i i 1 I i \\ l i j i i i l l ) l
l s j, Georgia Power Company i { l On April 30, 1990, j the Act ng P Assistant Genera nager - Plant Support l ave the VEGP General Manager a 1 tin of IB DG starts, i i ) 1 After being informed that v.he April 19 DG start counts were in error, the Senior Vice President - Nuclear Operations informed the Regional Administrator that a revision to the April 19 LER would be sul ditted, in part, to correct the DG start counts. After bajag provided conflicting data for the second time, the Senior Vice President - Nuclear Operations l again notified the Regional Administrator. He also j requestad that an audit be conducted by GPC's Safety Audit i and Engineering Review (SAER) group to establish the correct data and to determine why the errors were made. The audit, completed June 29, narrowly focused on a review of diesel i records (Test Data Sheets, Shift Supervisor's Log, and l Diesel Generator Start Log) to verify the number of DG i starts. The audit did not identify any specific cause for the error in the number reported in the LER. The audit { stated, however, that the error appeared to result from j incomplete documentation. The audit also noted that there j 1 apparently was some confusion about the specific point at l which the te a was co ted. 4 l t \\ On June 29, 1990, the draft cover letter for the LER revision was being reviewed at the site. The draft had originated in GPC corporate headquarters and included language personally developed by the Senior Vice President - Nuclear Operations and the Vice President - Vogtle Project. I During the site review, a VEGP Technical Assistant (TA) l (formerly the Acting VBGP Assistant General Manager - Plant j Support) noted that the letter was incomplete and challenged j the accuracy of the reasons stated in the draft cover-letter in conversations with the Supervisor - SAER, the VEGP Assistant General Manager - Plant Support, the VEGP Manager j - Engineering Support, and a Licensing Engineer - Vogtle j Project. The VEGP TA stated that: (1) the letter failed to i clarify the DG starts reported on April 9, (2) DG record keeping practices were not a cause of the difference in the DG starts reported in the April 19 LER because adequate
i ). 1 1 1 1 j Georgia Power Company I, i 1 i. Although OI'is inUestigation primaiily l 'foctased on actions and communications involving the DGs, OI also j reviewed other communications within a particular time-frame and j made a general observation that GPC exhibited a closed, ,i adversarial attitude toward the NRC. i b i 1 I i i l l l i i i e i i 1 I i l 4 t 4
Georgia Power Company. The responses directed by this letter and the enclosed Notice are not subject to the clearance procedures of the Office of. Manage-ment and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No. 96-511. Sincerely, i i l Jamer L. Milhoan i Deputy Executive Director for Nuclear Reactor Regulation, 4 Regional Operations,and Research
Enclosures:
1. Notice of Violation 1 l .2. Demand For Information Regarding Messrs. Thomas V. Greene, Georgie R. Frederick, Harry W. Majors, and Michael W. Horton j 3. Demand For Information Regarding Mr. C. ? Kenneth McCoy 1 4. Demand For Information Regarding Mr. George Bockhold, Jr. 1 4 i j i l j 4 1
i 4 _ Ws ~' f PREDECISIONAL INFORMATION f- '~ y*. l NOTJOR R_ E WITHOUT THE APPROVAL M THE DIRECTOR, OE Rev. 5: VOGNOVCP.R5 3/3/94 4 l NOTICE OF VIOLATION ese Georgia Power Company Docket No. 50-424 Vogtle Electric Generating Plant License No. NPF-68 EA 93-304 1 l During an NRC inspection conducted from August 6, 1990 to ) j August 17, 1990 and an NRC investigation completed on i l December 17, 1993, violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, i j andix C, t a Nuclear Regulatory Commission proposes to impose l pursuant to Section 234 of the Atomic Energy Act j of 1954, as amended ( 42 U.S.C. 2282, and 10 CFR 2.205. The .particular violations are set I forth below: i 10 CFR 50.9(a) requires that information provided to the NRC I by a licensee shall be complete and accurate in all material l respects. l 4EEur l 0 letter i l es tha : "Since March 20, 1A DG has been ] started 18 times, and the 1B DG has been started 19 times. No failures or problems have occurred during any of these l starts." s i i l 4 j Start 132 trippea on high, temperature lube oil, Start 134 tripped on low pressure 4 4 jacket water and Start 136 had a high tamperature jacket water trip alarm. As of April 9, 1990, the 1B DG had only 12 consecutive successful starts without problems or j failures rather than the 19 represented by GPC. The same ) inaccuracy was presented to the NRC at its Region II Office l during an oral presentation by GPC on April 9, 1990. i i
l i' { ~ Notice The NRC relied, in part, upon j this information presente y GPC on April 9, 1990 in the oral presentation and in the GPC letter in reaching the NRC decision to allow W e Unit 1 to return to power operation. VEG P ) i l n il 1990 letter l states, when d cussing r qua ity of the DG starting air system at the vogtle faciJ ity, that: "GPC has re'rieved air quality of the D/G air system including dewpoint control ] and has concluded that air quality is satisfactory. Initial j reports of higher than expected dewpoints were later l attributed to faulty instrumentation." i j occurre a Vogtle facility. f the causes of those high dew j points nelu d fai ure to use air dryers for extended i periods of time and repressurization of the DG air start j system receivers following maintenance, i j The NRC relied, in part, j upon this information presen d by GPC in its letter of l April 9, 1990 in reaching the decision to allow Vogtle Unit 1 to return to power operation. l i l consee Event R rt t ril 19 19 i j states: s senso ca ing ja et j water temperatures), special pneumatic leak testing, and l multiple engine starts and runs were performed under various j conditions. After the 3-20-90 event, the control systems of both engines have been subjected to a comprehensive test i program. Subsequent to this test program, DG1A and DGlB have been started at least 18 times each and no failures or problems have occurred during any of these starts." l ng the completion of the compre ans ve test program of the control systems for these DGs, when, in i fact, following completion of the comprehensive test program l of the control systems, there were no more than 10 and 12 consecutive successful starts without problems or failures j for lA DG and 1B DG respectively. i
i 4 1. Notice i l 4 E a 1 i. A m h states that: "In accordance with 10 CFR 50.73, j Georgia Power Company (GPC) hereby submits the enclosed revised report related to an event which occurred on i March 20, 1990. This revision is necessary to clarify the information related to the number of successful diesel generator starts as discussed in the GPC letter dated April 9, 1990...." i i 1 1 The Ketter states that: "If the criteria for the completion of th test program is understood to be the first successful l test n accordance with Vogtle Electric Generating Plant (VEG ) procedure 14980-1 " Diesel Generator Operability Test ' then there were 10 successful starts of Diesel Gener tor LA and 12 successful starts of Diesel Generator 1B betv n the completion of the test program and the and of i Apri 19, 1990, the date the LER-424/1990-06 was submitted to t a NRC. The number of successful starts included in the 4 j original LER (at least 18) included some of the starts that I ~3-
I J Notice l wereMartofthetestprogram. The difference is attbibuted to diesel start record keeping practices and the definition of the end of the test program." l 1 ] I i N 5%g , g ) 4 0 0 e T ApWe%%'.sf etie' P ?a4 ".w'.h k as ao
l 1 1 i i j Notice { 990 j states that: "The confusion in the April 9th j la er and the original LER appear to be the result of two { factors. First, there was confusion in the distinction between a successful start and a valid test... Second, an I error was made by the individual who performed the count of DG starts for the NRC April 9th letter." 1 1 i l l 1 4 } i ) i I l l l 4 e I e ] -..s i i l t I l ! s 1 l
l. i l I.- Notice c. ~. i i 4 Dated at (City, State) this day of (Month) 19(XX) 1 O e 1 s r d DRAFT j r PREDECISIONAL INFORMATION' /. OE NO/ TOR REJ.Eh8B WITROUT THE APPROYAL OF THE DIRECTOR, ) j Rev. 6: VOGDFIl.RC 3/8/94 UNITED STATES NUCLEAR REGULATORY COMMISSION i 1 In the Matter of ) ) GEORGIA POWER COMPANY ) l (Vogtle Electric Generating ) Docket Nos. 50-425/50-425 l Plant, Units 1 & 2) ) License Nos. NPF-68/NPF-81 1 ) EA 94-036 1' I DEMAND FOR INFORMATION REGARDING THOMAS V. GREENE, GEORGIE R. FREDERICK, j HARRY MAJORS, AND MICHAEL W. HORTON 1 I Georgia Power Company (Licensee) is the holder of Facility 4 License Nos. NPF-68, and NPF-81 (Licenses) issued by the Nuclear Regulatory Commission (NRC or Commission) pursuant to 10 CFR a i Part 50. The Licenses authorize the operation of the Vogtle Electric Generating Plant (VEGP) Units 1 and 2, in accordance with conditions specified therein. II i j On December 17, 1993, an investigation of licensed activities was completed by the NRC's Office of Investigations (OI) a,t Licensee's VEGP facility. The investigation was initiated in response to information received in June 1990 by NRC Region II l alleging, in part, that material false statements were made to the NRC by senior Licensee officials regarding the reliability of l
. ~. -. -. ' the Diesel Generators (DGs). The pertinent events involv d in this matter are described below. I On March 20, 1990, during a refueling outage at VEGP Unit 1, GPC. ] declared a Site Area Emergency (SAE) when offs'ite power was lost concurrent with the failure of the only Unit 1 DG that was available (1A). The other Unit 1 DG (1B) was unavailable due to maintenance activitiec. The NRC immediately responded to the SAE at the VEGP with an ,- Augmented Inspection Team (AIT). The NRC effort was upgraded to an Incident Investigation Team (IIT) on March 23, 1990. The IIT was composed of NRC Headquarters technical staff and industry . personnel. The results of this investigation are documented in NUREG-1410, " Loss of Vital AC Power and the Residual Heat Removal System During Mid-Loop Operations at Vogtle Unit 1 on March 20, i 1990." On March 23, 1990, the NRC issued a Confirmation of Action Letter (CAL) to GPC that, among other things, confirmed that GPC had agreed not to return VEGP Unit 1 to criticality until.the Regional Administrator was satisfied that appropriate corrective i actions had been taken, and that the plant could safely return to power operations. l 1 J
_3_ On April S, 1990, GPC made a presentation to the NRC in the Region II offices in support of GPC's request to return VEGP Unit 1 to power operations. As part of this presentation, GPC provided information on DG starts in response to a specific NRC request that GPC address DG reliability in its April 9 presentation. 3PC submitted a written-summary of its April 9 presentation in an April 9, 1990 letter, "Vogtle Electric Generating Plant Confirmation of Action Letter." On April 12, 1990, the NRC formally gra'nted permission for VEGP . Unit 1 to return to criticality and resume power operations. On April 19, 1990, pursuant to 10 CFR 50.73, GPC submitted Licensee Event Report (LER) 50-424/90-06, " Loss of Offsite Power Leads to Site Area Emergency." f On June 29, 1990, GPC submitted a revised LER, 50-424/90-06-01. The purpose of the submittal was to clarify information related to successful DG starts that were discussed in the April 9, 1990 ' ) letter and the April 19, 1990 LER, and to update the status of corrective actions in the original LER. t From August 6 through August 17, 1990, the NRC conducted a Special Team Inspection at VEGP, as a result of NRC cor.Oerns about, and allegations related to, VEGP operationa). activities. This inspection examined the technical validity and safety 4
l -4_ i significance of the allegations, but did not investigate alleged i wrongdoing. The Special Team informed GPC that the June 29, 1990 submittal failed to address the April 9, 1990 data and requested that GPC clarify DG starts reported on April 9, 1990. Results of this inspection are documented, in part, in NRC Inspection Report No. 50-424,425/90-19, Supplement 1, dated November 1, 1991. i 1 l On August 30, 1990, GPC submitted a letter, " Clarification of Response to Confirmation of Action Letter." The purpose of the . submittal was to clarify the diesel start information that was addressed in the April 9, 1990 submittal. m 4 III The NRC has reviewed the evidence associated'with these events, submittals, and representations to the NRC. Specifically, the NRC reviewed information gathered as part of the OI investigation, information gathered during the IIT, NUREG-1410, Supplement 1 of NRC Inspection Report 90-19, discovery responses in the Vogtle operating license amendment proceeding (Docket Nos. 50-424 OLA-3, 50-425 OLA-3), and other related information. The NRC has identified apparent violations of regulatory requirements involving five separate instances that occurred from April 9 to August 30, 1990, where the Licensee failed to provide information that was completo and accurate in all material
l I. 5-1 l 4 i i s i r-- 3. .s .s. !~ 4 1 d On June 29, 1990, the draft cover letter for the LER revision was i being reviewed at the VEGP site. The draft had originated in GPC j corporate headquarters and included language personally developed ~ by the Senior Vice President - Nuclear Operations (George W. j i Hairston, III) and the Vice President - Vogtle Project (C. Kenneth McCoy). During this review, a VEGP Technical Assistant (TA) (formerly the Acting VEGP Assistant General Manager - Plant Support) (Alan L. Mosbaugh) noted that the draft cover letter was incomplete and challenged the accuracy of the respons stated in the draft cover letter in conversations with the Supervisor - Safety Audit and Engineering Review (SAER) (Georgie R. Frederick), the VEGP Assistant General Manager - Plant Support (Thomas V. Greene), the VEGP Manager - Engineering Support j
s . (Michael W. Horton), andaLicensingEngineer-VogtlePrhject (Harry W. Majors). Mr'. Mosbaugh stated that: (1) the letter failed to clarify the DG starts reported on April 9, 1990 (2) DG record keeping practices were not a cause of the difference in the DG starts reported in the April 19, 1990 LER because adeguate information to formulate an accura :e count was available when the counting errors were made, and (3) the erroneous counts resulted from personnel errors in developing the count. sumer 88 mum Mr. Majors had staff responsibility for preparing the cover l letter for the LER revision and was specifically instructed by the Senior Vice President - Nuclear Operations to work closely with the site to ensure that the submittal was accurate and complete. Mr. Horton was responsible for the Diesel Start Logs and agreed with the audit report findings regarding deficiencies in their condition. Given that his logs had not been used to collect the l I
j DG start data, he pointed out tha,t it was wrong to state that the conditionofhislogscausederrorsintheinformationiniIially provided to the NRC. e-4 c s Mr. Frederick was made aware by Mr. Mosbaugh j on June 12, 1990 that, to identify the root cause of the error in I the April 19, 1990 LER (i.e., personnel errors), the audit scope i would need to include an assessment of the performance of the i Unit Superintendent and the VEGP General Manager, the individuals j that developed the initial count. Yet, the audit report did not include either of these individuals in the list of persons i I
~ _ _ _ Il. l l r 8-contacted during the audit. On June 29, 1990, Mr. Frederick was again made aware by Mr. Mosbaugh that the root cause for the difference was personnel error. ~~ Mr. Greene was apprised of concerns regarding the June 29, 1990 letter by Mr. Mosbaugh (an individual who had been involved in preparing the April 19, 1990 LER and had been involved in developing an accurate DG start count). Mr. Mosbaugh identified to him the failure of the June 29, 1990 draft cover letter to address the inaccuracies in the April 9, 1990 letter that it referenced and Mr. Mosbaugh pointed out the erroneous causes stated for the reasons for the difference in the June 29, 1990 DG start counts. O se f )
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ga-- s_ i .j FOR THE NUCLEAR REGUIATORY COMMISSION i i a I James L. Milhoan i Deputy Executive Director l for Nticlear Reactor Regulation, j-Regional Operations, and Research i j Dated at Rockville, Maryland i this day of (Month) 19(XX) 1 i t i ) i 4 I d 9 1 i W E
4 DRhPT n % 'PREDICISIONAL INFORMATION ' ' w NOT RELEASE YITIOUT THE APPROVAL'OP THE DIRECTOR,'.OE Rev. 6: VOGDFI2.R6 3/8/94 UNITED STATES NUCLEAR REGULATORY COMMISSION i In the Matter of ) i
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GEORGIA POWER COMPANY ) (Vogtle Electric Generating ) Docket Nos. 50-425/50-425 2 Plant, Units 1 & 2) ) License Nos. NPF-68/NPF-81 j ) EA 94-052 DEMAND FOR INFORMATION REGARDING C. KENNETH McCOY I j l Georgia Power Company (Licensee) is the holder of Facility License Nos. NPF-68, and NPF-81 (Licenses) issued by the Nuclear Regulatory Commission (NRC or Commission) pursuant to 10 CFR i I Part 50. The Licenses authorize the operation of the Vogtle Electric Generating Plant (VEGP) Units 1 and 2, in accordance with conditions specified therein. II on December 17, 1993, an investigation of licensed activities was completed by the NRC's Office of Investigations (OI) at Licensee's VEGP facility. The investigation was initihted in response to iniornation received in June 1990 by NRC Region II alleging, in part, that material falso statements were madr,to the NRC by senior Licensee officials regarding the reliability of the Diesel Generators (DGs). The pertinent events involved in this matter are described below.
' On March 20, 1990, during a refueling outage at VEGP Unit 1, GPC declared a Site Area Emergency (SAE) when offsite power was lost concurrent with the failure of the only Unit 1 DG that was available (1A). The other Unit 1 DG (1B) was unavailable due to maintenance activities. The NRC immediately responded to the SAE at the VEGP site with an Augmented Inspection Tcda (AIT). The NRC effort was upgraded to an Incident Investigation Team (IIT) on March 23, 1990. The IIT was composed of NRC Headquarters' technical staff and industry personnel. The results of this investigation are documented in NUREG-1410, " Loss of Vital AC Power and the Residual Heat Removal f System During Mid-Loop Operations at Vogtle Unit 1 on March 20, j 1990." i I On March 23, 1990, the NRC issued a Confirmation of Action Letter (CAL) to GPC that, among other things, confirmed that GPC had l l agreed not to return VEGP Unit 1 to criticality until the l Regional Administrator was satisfied that appropriate corrective actions had been taken, and that the plant could safely return to power operations. I i On April 9, 1990, GPC made a presentation to the NRC in the J Region II offices in support of GPC's request to return VEGP Unit 1 to power operations. As part of this presentation, GPC provided information on DG starts in response to a specific NRC
I I e request that GPC address DG reliability in its April 9 presentation. GPC submitted a written summary of its April 9 presentation in an April 9, 1990 letter, "Vogtle Electric j Generating Plant Confirmation of Action Letter." i l On April 12, 1990, the NRC forrrily granted permission for VEGP Unit 1 to return to criticality and resume power operations. On April 19, 1990, pursuant to 10 CFR 50.73, GPC submitted Licensee Event Report (LER) 50-424/90-06, " Loss of Offsite Power i , Leads to s te Area Emergency. On June 29, 1990, GFC submitted a revised LER, 50-424/90-06-01. The purpose of the submittal was to clarify information related to successful DG starts that were discussed in the April 9, 1990 4 letter and the April 19, 1990 LER, and to update the status of corrective a'ctions in the original LER. I t l From August 6 through August 17, 1990, the NRC conducted a special Team Inspection at VEGP, as a result of NRC concerns about, andallegationsrelatedto,VEGPoperationalactpvities. This inspection examined the technical validity and ' safety signifi.cance of the allegations, but did not investigate alleged wrongdoing. The Special Team informed GPC that the June 29, 1990 submittal failed to address the April 9, 1990 data and requested that GPC clarify DG starts reported on April 9, 1990. Results of 4
-4 this inspection are documented, in part, in NRC InspectioS Report No. 50-424,425/90-19, Supplement 1, dated November 1, 199'1. On August 30, 1990, GPC submitted a letter, " Clarification of Response to confirmation of Action Letter." The purpose of the submittal was to clarify the diesel start information that was j l addressed in the April 9, 1990 submittal. j III l The NRC has reviewed the evidence associated with these events, submittals, and representations to the NRC. Specifically, the NRC reviewed information gathered as part of the OI investigation, information gathered during the IIT, NUREG-1410, Supplement 1 of NRC Inspection Report 90-19, discovery responses in the Vogtle operating license amendment. proceeding (Docket Nos. 50-424 OLA-3, 50-425 OLA-3), and other related information. l O a O 4 \\
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l i I i i 1 i Mr. McCoy was actively involved in the preparation of the i l June 29, 1990 cover letter and reviewed it prior to forwarding it i to the Senior Vice President - Nuclear Operations for signature I l and issuance. The June 29, 1990 cover letter stated that its l l purpose was, in part, to clarify information provided to the NRC on April 9, 1990. i l 6 i 1 I l l I i l Mr. McCoy committed during i I the August 17, 1990 meeting with the NRC Special Inspection Team J I to provide clarification to the NRC regarding the April 9, 1990 i letter. a i i i l l i t 4 1 1
FOR THE NUCLEAR REGULATORY COMMISSION James L. Milhoan Deputy Executive Director for Nuclear Reactor Regulation, Regional Operations, and Research Dated at Rockville, Maryland this day of (Month) 19(XX) e 1 i t j. 4 i b i W 4 4 i
l Y l i /s y PRIDECISIONAL INFORMATION ! OT OR-RELEASE'WITEOUT TEE APPROVAL'OF THE DIRECTOR, OE. l Rev. 5: VOGDFI3.R5 3/4/94 I UNITED STATES i NUCLEAR REGULATORY COMMISSION In the Matter of ) ) GEORGIA POWER COMPANY ) (Vogtle Electric Generating ) Docket Nos. 50-425/50-425 Plant, Units 1 & 2) ) License Nos. NPF-68/NPF-81 l ) EA 94-036 DEMAND FOR INFORMATION l REGARDING GEORGE BOCKHOLD, JR. i j I i j Georgia Power Company (Licensee) is the holder of Facility j License Nos. NPF-68, and NPF-81 (Licenses) issued by the Nuclear l l Regulatory Commission (Nnc or Commission) pursuant to 10 CFR i Part 50. The Licenses authorize the operation of the Vogtle i i j Electric Generating Plant (VEGP) Units 1 and 2, in accordance i with conditions specified therein. 4 I { i II I i l On December 17, 1993, an investigation of licensed activities was completed by the NRC's Office of Investigations (OI) at i Licensee's VEGP facility. The investigation was initiated in i response to information received in June 1990 by NRC Region II alleging, in part, that material false statements were made to j the NRC by senior Licensee officials regarding the reliability of j the Diesel Generators (DGs). The pertinent events involved in i 2 this matter are described below. l
. _ _ = _ _ _. _ On March 20, 1990, during a refueling outage at VEGP Unit 1, GPC declared a Site Area Emergency (SAE) when offsite power was lost concurrent with the failure of the only Unit 1 DG that was available (1A). The other Unit 1 DG'(1B) was unavailable due to maintenance activities. The NRC immediately responded to the SAE at the VEGP site with an i Augmented Inspection Team (AIT). The NRC effort was upgraded to an Incident Investigation Team (IIT) on March 23, 1990. The IIT I was composed of NRC Headquarters technical staff and industry ' personnel. The results of this investigation are documented in NUREG-1410, " Loss of Vital AC Power and the Residual Heat Removal System During Mid-Loop Operations at Vogtle Unit 1 on March 20, 1990." On March 23, 1990, the NRC issued a Confirmation of Action Letter (CAL) to GPC that, among other things, confirmed that GPC had 1 j agreed not to return VEGP Unit 1 to. criticality until the j i 1 j Regional Administrator was satisfied that appropriate corrective j actions'had been taken, and that the plant could safely return to l power operations. i l On April 9, 1990, GPC made a presentation to the NRC in the I l Region II offices in support of GPC's request to return VEGP 4 ( Unit 1 to power operations. As part of this presentation, GPC j l provided information on DG starts in response to a specific NRC l
l, request that GPC address DG reliability in its April 9 presentation. GPC submitted a written summary of its April 9 presentation in an April 9, 1990 letter, "Vogtle Electric Generating Plant Confirmation of Action ~ Letter." On April 12, 1990, the NRC formally granted permission for VEGP Unit 1 to return to criticality and resume power operations. l On April 19, 1990, pursuant to 10 CFR 50.73, GPC submitted Licensee Event Report (LER) 50-424/90-06, " Loss of Offsite Power i Leads to site Area Emergency." On June 29, 1990, GPC submitted a revised LER, 50-424/90-06-01. The purpose of the submittal was to clarify information related to successful DG starts that were discussed in the April 9, 1990 letter and the April 19, 1990 LER, and to update the status of corrective actions in the original LER. From Nugust 6 through August 17, 1990, the NRC conducted a Special Team Inspection at VEGP, as a result of NRC concerns ) about, and allegations related to, VEGP operational activities. i i This inspection examined the ts hnical validity and safety I significance of the allegations, but did not investigate alleged l wrongdoing. The Special Team informed GPC that the June 29, 1990 i submittal failed to address the April 9, 1990 data and requested that GPC clarify DG starts reported on April 9, 1990. Results of
A - 4:- this inspection are documented, in part, in NRC Inspection Report No. 50-424,425/90-19, Supplement 1, dated November 1, 1991. On August 30, 1990, GPC submitted a letter, " Clarification of Response to Confirmation of Action Letter." The purpose of the submittal was to clarify the diesel start information that was addressed in the April 9, 1990 submittal. III The NRC has reviewed the evidence associated with these events, submittals, and representations to the NRC. Specifically, the NRC reviewed information gath'ered as part of the OI investigation, information gathered during the IIT, NUREG-1410, Supplement 1 of NRC Inspection Report 90-19, discovery responses in the Vogtle operating license amardment proceeding (Docket Nos. 50-424 OLA-3, 50-425 OLA-3), and other related information. l The NRC has identified apparent violations of regulatory requirements involving five separate instances that occurred from j April 9 to August 30, 1990, where the Licensee failed to provide information that was complete and accurate in all material respects. These violations are addressed in tha Notice of I Violation and Proposed Imposition of Civil Penalties issued to i the Licensee on this date, and incorporated herein by reference. i i j l l t
4 i - ~ j 1 i n a..+m a..a i Prior to GPC briefing the Regional Administrator, Region II, on VEGP's readiness for restart, the NRC asked GPC to address DG 1 reliability as,part of its restart presentation on April 9, 1990. I For that presentation, Mr. Bockhold was personally involved in f the preparation of data regarding DG reliability and. tasked the Unit Superintendent with collecting the number of successful DG f starts for the 1A and 1B'DGs. 1 i i { In fact, Mr. Bockhold stated no criteria for successful starts, a term not formally defined, when he directed the Unit Superintendent to gather successful DG starts. e f 1
1 i l' l- ) -~6.- i l Information was then presented to the NRC in the ,j j April 9, 1990 oral presentation by Mr. Bockhold 'and the April 9, 4 1990 letter submitted by GPC tlaat there were 18 and 19 l 1 consecutive successful starts on the 1A and 1B DGs, respectively, without problems or failures. ] GPC's i report of starts in the presentation and letter included three 1B DG starts with problems that occurred during DG overhaul and maintenance activities (a high lube oil temperature trip on March 22, 1990; a low jacket water pressure / turbo lube oil j pressure low trip on March 23, 1990; and a failure to trip on a j high jacket water temperature alarm occurring on March 24, 1990). The correct number of consecutive successful starts without problems or failures was 12 for 1B DG--a numbe less than that reported by GPC to the NRC on April 9, 1990. i i i i 1 1 1 LER 90-006, submitted to the NRC on April 19, 1990, was based, in part, on information presented to the NRC on, April 9, 1990dEEEP 1 l k
i 7-During review of the draft LER, site j personnel questioned its accuracy. Given that there were trips in the 1B DG after March 20, 1990, they did not think that the i statement concerning "no problems or failures" was correct. A teleconference was subsequently held between site and corporate personnal l I 4 4 l i l I .i 0 9 'I l 4 1
- - _ _.... ~.. -.. the 1A and 1B DG start counts reported on April 19, 1990 overstated the actual counts by including starts that were part of the CTP. I 1 ( t I I j l i i ) i I o O s a I i
l [ i* i l 4 4 1 J .e 4. ) i. p.,..m:.++. p. r ~~ j ~. The Senior Vice President - Nuclear Operations ] d j also stated that he thought the April 19,,1990 data had been ) checked. i i i ] On'May 2, 1990, Mr. Bockhold was given a list of DG starts that l showed that the start counts reported in the April 9, 1990 I j presentation, the April 9, 1990 CAL response letter, and the April 19, 1990 LER were incorrect. Mr. Bockhold agreed that the j LER needed to be revised to reflect the correct number of starts. Mr. Bockhold also agreed that the April 9, 1990 letter needed to be corrected because he asked and was informed that the April 9, i I 1990 error was different than the April 19, 1990 error. It was i also agreed that uniform language would be used to correct both j documents. i i et n. s:+'e
J. I 4 d During the NRC's Special Team Inspection exit interview on 4 August 17, 1990, GPC was specifically notified by the NRC that the revised LER did not adequately clarify the DG start i information contained in the April 9, 1990 letter, and NRC requested GPC to provide clarification of this submittal. GPC l forwarded a submittal to the NRC on August 30, 1990 regarding the April 9, 1990 letter. A draft of the August 30, 1990 letter, sent to the site for review, suggested that one of the reasons for the error in the April 9, 1990 letter was " confusion in the distinction between a successful start and a valid test" by the individuals who prepared the DG start i information for the April 9, 1990 letter. During an August 29, 1990 Plant Review Board (PRB) meeting which, among other things, reviewed the proposed August 30, 1990 submittal to the NRC, the VEGP Manager - Technical Support raised concerns about the i accuracy of that statement. Mr. Bockhold admitted to the PRB that the Unit Superintendent (who originally collecte'd the DG start data at Mr. Bockhold's direction) was not confused about the distinction between successful starts and valid tests when the start data was collected for the April 9, 1990 letter, but stated that the sentence was not in error because other people were confused. Mr. Bockhold acknowledged that there was
l l 11 - i confusion among individuals after April 9, 1990, but admitted that the Unit Superintendent was not confused when he developed the information. p. e Mr. Bockhold was aware of the NRC's interest in DG reliability in the context of an NRC decision on restart O e we
( .,, + + + + + n,.... m : ~~ c' FOR THE NUCLEAR REGUIATORY COMMISSION James L. Milhoan Deputy Executive Director for Nuclear Reactor Regulation,- Regional Operations, and Research i Dated at Rockville, Maryland this day of (Month) 19(XX) 4 e
~- 6, uNITto s._ '[ NUCLE AR REGULATORY iNHsSION 2 e REC 40 Nil .I 101 MAAltTTA St Att7,N.W. 7 ATL ANT A CEORCIA 303H %,*..../ Docket Nos. 50-424, 50-425 License Nos. NPF-68, NPF-81 DEC 0 21991 ) Georgia Power Company i ATTN: Mr. W. G. Hairston, !!! Senior Vice President - Nuclear Operations P. O. Box 1295 Birmingham, AL 35201 Gentlemen:
SUBJECT:
NRC INSPECTION REPORTS NOS. 50-424/91-30 AND 50-425/91-30 This refers to the special inspection conducted by the Nuclear Regulatory Commission (NRC) Augmented Inspection Team (AIT) at your Vogtle Electric Generating Plant (VEGP) during the period of October 29 - November 1,1991, ) concerning a loss of Decay Feat Re90 Val capability.that occurred on October 26, 1991. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed inspection report. The enclosed copy of the AIT report identifies the areas examined during this inspection. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activiti.es in progress. The AIT concluded that the event was caused by a combination of factors including a coninon mode failure to all reactor vessel level instrumentation that was being used to monitor level in the reactor vessel and an inadequate control of a temporary modification connected to the primary system. A review of the inspectier, findings is continuing to deterr.ine whether the described activities violate NRC requirements. You will be advised by separate correspondence of the results of our review on this matter. In acccrdance wi{h Section Z.750 of the NRC's " Rules vi Fractice," a copy of this letter and the enclosure will ce placed in the NRC Pubin; Occument Recc. Should you have any questions concerning this letter, please contat.t us. Sincerely, Information in this record was deleted 4 in accordance with the freedom of Information k/ Act. exemptions I MMN d F0fA.__f.f.2 // Stewart D. Ebneter Regional Administrator n l
Enclosure:
i NRC Inspection Report 3p gC5CP'
i I Georgia Power Company 2 ) cc w/ encl: DEC 02 ;gg; R. P. Mcdonald Executive Vice President-Nuclear i Operations j Georgia Power Company P. O. Box 1295 j Birmingham, AL 35201 l C. K. McCoy Vice President-Nuclear Georgia Power Company P. O. 1295 Birmingham, AL 35201 l 1 W. B. Shipman General Manager Nuclear Operations Georgia Power Company P. O. 1600 Waynesboro, GA 30830 ] J. A. Bailey i , Manager-Licensing j Georgia Power Company i P. O. Box 1295 j Birmingham, AL 35201 l D. Kirkland, !!!, Counsel ) Office of the Censumer's Utility Council Suite 225, 32 Peachtree Street, NE Atlanta, GA 30302 Office of Planning and Budget i Room 6158 i 270 Washington Street, SW Atlanta, GA 30334 Office of the County Comissioner Burke County Comission i Waynesboro, GA 30830 Joe D. Tanner, Comissioner Department of Natural Resources 205 Butler Street, SE, Suite 1252 ~ Atlanta, GA 30334 Thomas Hill, Manager Redioactive Materials Program j Department of Natural Resources 4244 International Parkway (cc w/erci ceat'd - see one 3' i
i l I Georgia Power Company 3 DEC 02 mst i cc w/ encl: (Continued) Suite 114 Atlanta, GA 30354 l Attorney General Law Department 132 Judicial Building Atlanta, GA 30334 i Dan Smith, Program Directr of Power Production Oglethorpe Power Corporation 2100 East Exchange Place P. O. Box 1349 Tucker, GA 30085-1349 Charles A. Patrizia Esq. Paul, Hastings, Janofsky & Walker 12th Floor 1050 Connecticut Avenue, NW Washington, D. C. 20036 i 4 1 e
4"* " 8% UNITED ST ATES J' NUCLEAR REGULATORY COMMisslON [ 'e RE Ctr>N il p 101 M A AtET T A ST RE ET.N.W. 3 ,, g ATL ANT A, C E ORCI A 30323 \\,...../ Report Nos.: 50-424/91-30 and 50-425/91-30 Licensee: GeorgiaPowerCompanj Docket Nos.: 50-424 and 50-425 License Nos.: NPF-68 and NPF-81 facility Name: Yogtle Electric Generating Plant Units 1 and 2 Inspection Conducted: October 29 - November 1, 1991 Team Members: B. Breslau, Reactor Inspector, Rll G. Galletti, Human factors Specialist, NRR j C. Liang, Senior Reactor Systems Engineer, NRR D. Star y, Resident inspe: tor - Vogtle, Ril j 1 ct<k/! t h /[fF.29, /9f/ Team Leader: P. Skinner Section Chief, Reactor Date Signed Projects Section 3B, D.ivision Reactor Projects, Ri! 0 A d
d TABLE OF CONTENTS l d P,agg, I. Introduction - Ali Formation and Ini tiation............... 1 i A. Background............................................ 1 8. AIT Formation......................................... 1 C. AIT Charter - Inspection Ini tiation................... 1 D. Pe rs ons C ontac ted..................................... 2 E. Ac r o nyms.............................................. 2 F. D oc ume n ts R e v i ewed.................................... 2
- 11.. E v e n t Des c r i p t i on.......................................... 2 A.
Event Overview for Vogtle Uni t 1...................... 2 B. Initial Conditions.................................... 3 i I C. Detailed Sequence of Events as Verified by the AIT and Licensee Personnel..................... 3 111. Radiation Protection....................................... 6 IV. Safety System Performance and Plant Proximity To Sa f e ty L imi ts as De fined................................. 6 V. P roc e d u re s Re v i ews.......................................... 7 VI. T r a i n i n g................... ~................................. 8 V I I. O pe ra to r Ac ti on s............................................ 9 Vllt. Reactor Control System Water Level Instrumentation............................................ 10 IX. " B " RHR P ump Ope ra bi l i ty.................................... I l X. S i gh tgl a s s Modi fica tion.................................... 13 XI. Gene ri c Letter 88-17 Ac ti ons............................... 13 XII. Human Performance implica tions............................ 14 A. Introduction......................................... 14 B. Contributing Causes.................................. 15 1. C ommun i c a t i ons.................................. 15 2. Design Control Practices......................... 16 3. Procedu ral Fac tors............................... 17 XI!!.Reportabality.............................................. 17 XIV. Conclusions ..............v................................ 18 XV. Ex i t Interview with Licensee Management................... 19 A
APPENDICES Appendix A Persons Contacted.......................... 20 Appendix B Acronyms.................................... 21 Appendix C Documents Reviewed.......................... 22 FIGURES Figure 1 RHR System Simplified Diagram Figure 2 RCS Siteglass Header Simplified Drawing Figure 3 Mid Loop Level Instrumentation Range Information Figure 4 Event and Causal Factors Chart i l
J i l 1. INTRODUCTION - Ali FORMATION AND INITIATION' ) A.
Background
j Vogtle Electric Generating Plant Units 1 and 2 are four reactor coolant loop Westinghouse pressurized water reactors rated at 3411 MW i thermal. The units are located approximately 26 miles southeast of Augusta, Georgia in Burke County. Unit I received a full power operating license in March 1987, and Unit 2 in March 1989. I B. AIT Fonnation ) On the morning of Monday, October 28, 1991, the Regional Administrator, after further briefing by the regional and resident staff and consultation with senior NRC r.anagement, directed the i formation of an Ali with Region 11 and NRR personnel. The AIT was to be headed by a Region !! Reactor Projects Section Chief. The basis i for the formation of the AIT was to gain a clearer understanding of l the event related to the degradation of Decay Heat Removal that occurred at Vogtle Unit 1 on October 26,'1991. j C. AIT Charter - Inspection Initiation-l The Charter for the AIT was prepared on October 28, 1991. The 4 special inspection corsnenced at 10:30 a.c. on October 29 with an l entrance meeting and VEGP licensee management briefing of the event. i The Charter for the AIT specified that the following tasks be l completed: i i 1. Develop and validate the sequence of events associated with the l October 26, 1991, degradation of decay heat removal at Vogtle. This secuence is to begin with plant conditions inriediately-prior to this event, including known significant deficiencies in safety-related and balance of plant equipment, and extend until L the plant was stable. 2. Evaluate the significance of this event with regard to l radiological consequences, safety system performance, fuel integrity and plant proximity to safety limits as defined in TS. I 3. Identify any human factors, training or procedural deficiencies ~ t related to this event. Evaluate operator actions during the event and subsequent equipment recovery. Specifically, evaluate the effectiveness of the procedures for recovery from loss of decay heat removal which were used during this event, and the l i requirerents for monitoring primary plant parameters such as reactor coolant temperature and pressure while shutdown and i during changes to the shutdown cooling lineup. 4. Evaluate the degree to which prior work planning for the outage could have precluded this event. Include the following aspects:
4 2 (a) independent verifications (b) verbal connunications, (c) outage control, and (d) system engineer involvement. 5. Evaluate the basis for the decision that this event was not reported to the NRC and evaluate the a#cuacy of the event classification. 6. Determine if the following played a significant role in this event: system modifications; plant material conditions; the quality of maintenance; or the responsiveness of engineering to identify problems. 7. Evaluate the effectiveness of management involvement during the event, the post event reviews, and subsequent recovery. 6. For each equipment malfunction or personnel error to the extent aractical, determine: a. Root cause. b. If the equipment was known to be deficient prior to the event. c. If equipment history would indicate that the j equipment had either been historically unreliable or if maintenance or modifications had been recently performed. d. Pre-event status of surveillance, testing (e.g., Section XI), and/or preventive maintenance. 9. Prepare a special inspection report documenting the results of the above activities within 30 days of inspection completion. 0. Persons Contacted See Appendix A E. Acrony.s See Appendix B i F. Do:uments Reviewed See Appendix C
- 11. Event Description A.
-Event Overview At approximately 10:30 p.m., on October 26, 1991, while Vogtle Unit 1 was in mode 6 (refueling) with the reactor vessel head off, the licensee was draining the cavity and reactor vessel to just below the l
3 reactor vessel flange to facilitate replacing the head. The "B" Residual Heat Removal (RHR) pump was in use for decay heat removal, while the "A" pump was being used to pump down the cavity and vessel. As draining continued, the licensee observed indications of cavitation on the "B" RHR pump. The "B" RHR pump was placed on minimum flow recirculation (miniflow) and the 'A' pump was realigned to take a suction from the RWST and used to raise water level in the vessel. Decay heat removal capability was restored after water level was reestablished. The reactor was without decay heat removal for approximately 16 minutes. Core temperature as indicated at the RHR pump discharge increased from approximately 87 degrees F to 107 degrees F. There was no radiological release to the environment. This event was reported by the licensee in LER 50-424,425/91-09: Loss of Residual Heat Removal Pump Flow During Draindown of Reactor Cavity. 8. Initial Conditions The unit was in day 42 of a scheduled 52 day refueling outage. Presently the schedule has been extended to approximately 68 days. C. Detailed Sequence of Events as Verified By the AIT and Licensee Personnel DATE/ TIME EVENT 10/26/91 3:32 p.m. "A" RHR pump secured following pump down of reactor cavity at 210'4" 6:20 p.m. USS comences shif t turnover process with his relief - topics include pending reactor cavity / vessel level decrease. APO inside containment notified by RO to monitor RCS tygon tube for level changes. 6:30 p.m. APO in containment called control room to establish communications for cavity draindown. Level watch was established at the new level sightglass. 6:33 p.m. Started "A" RHR pump to lower reactor cavity and vessel level from 210'4" to 192' at a flowrate of l l approximately 100 gpm to the RWST. 6:48 p.m. USS shift relief turnover completed. Off-going USS not aware that drain down had comenced. Reactor ) i
4 cavity level was at 208' at this time as indicated by the pressurizer level indicator (cold calibrated instrument) RCS level at 207' as read on Pressurizer cold level 7:25 p.m. instrumentation 1-LI-462 station at sightglass Oncoming PE0 relieves APO on 7:30 p.m. and discovers that valves HIH, DIH, and DIL are shut and valves GD and GV are open with caps installed. The APO and PE0 notify the control room and draining was stopped. The sightglass was then valved in and At that time the sightglass, tygon vented by the PEO. tube and visual cavity indication were all reported reading approximately 205'6". Draining was resumed at a flowrate of 1000 gpm. 8:10 p.m. RCS level at sightglass was 204'6". 8:34 p.m. RCS level at sightglass was 203'6". 8:59 p.m. RCS level at sightglass was 202'6". 9:14 p.m. RCS level at sightglass was 201'6". f 9:23 p.m. RCS level at sightglass was 198'6". 9:38 p.m. f At approximately 197' on the sightglass.the drain rate 9:47 p.m. was decreased from approximately 2500gpm to approximately 800gpm. An " Accumulator !4 Hi/Lo level" alarm (RCS High Level) 10:01 p.m. annunciator was received in the control room (ALB ] 06-D03). The RO tapped meter indicator 1-LI-957. The meter reading dropped immediately from 100% to 60%. (1-L1-957 was the indication associated with the level Draining was device providing this alarm signal.) ) The USS called I & C personnel to stopped. investigate 1-LI-957. At this time the sightglass ) was verified to read 194'. Reactor cavity level was also verified to be at 194' which is at the vessel The R0 decided that the sightglass was the flange. most rel'iable indication. Draindown continued to 192' at a rate of approximately 10:17 p.m. 675 gpm. 10:24 p.m. RCS level at sightglass 193'6". 10:31 p.m. RCS level at sightglass 193'. 1 i 1
9 5 10:33 p.m. Control room operators observed "B" RHR flow oscillations and decreasing pump discharge pressure indicative of cavitation. RHR flow and pump discharge pressure as observed by the RO decreased to O gpm and 0 psig. The R0 aligned the "B" RHR pump to miniflow alignment. LI-957 indicated approximately 30(188'3") L1-950 indicated approximately 601(187'6") - sightglass indicates 193' - Reactor vessel level reported approximately I' below flange (193') 10:34 p.m. Draindown was stopped by closing "A" RHR pump discharge valve placing pump in a miniflow lineup. Pump was then shutdown. Entered A0P 18019-C, Loss of RHR (Hid Loop LOCA) 10:38 p.m. "B" RHR pump cavitation stopped. Pump still on miniflow. room. 55 10:39 p.m. 55 paged to return to the control instructed operators to raise level to greater than the cavity floor level to remove any question as to RCS level. "A" RHR pump was aligned to pump water from RWST to RCS at a flowrate of 400 gpm. 10:44 p.m. Shut "A" RHR pump discharge valve and opened "B" discharge valve to establish a recirculation flowrate of 350 gpm. Attempted to increase flowrate to 3000 gpm cavitation noted and flow reduced to 1800 gpm. i 10:45 p.m. SS determined that the event did not require emergency classification. ~ 10:56 p.m. "A" RHR pump aligned to fill reactor vessel'at a flowrate of 400 gpm. l 11:10 p.m. Stopped vessel fill at an indicated level of approximately 194' at sightglass. 11:16 p.m. "B" RHR pump flow stabilized at 3000gpm.
I l 6 SS contacted Operations Manager to discuss event. 11:30 p.m. 10/27/91 Operations identifies sightglass top isolation valve. 12:15 a.m. Hil, closed and red tagged. Also discovered that a HEPA filter was connected to the top of the pressurizer safety valve flange with the attached hose collapsed. HEPA was turned off and a vent path for the Pressurizer established. SS contacted the Operations Unit Superintendent to 2:00 a.m. discuss reportability. It was decided that this event was not reportable. Assistant General Manager informed of event. He 6:30 a.m. proceeded to the s'ite to start event investigation and organize a critique team. 8:30 a.m. Vogtle event team established. i !!!. Radiation Protection At t>e time of this event, personnel were performing limited c.ain;enance activities outside the bioshield. There were approximately 30 to 40 personnel in containment, the majority of whom were HP technicians Decontamination was planned for the area and, decontamination personnel. near the vessel flange but work had not begun. There were two continuous air sample monitors close to the reactor cavity neither of which recorded any activity during this event. Following and during the event HP did not initiate any additional surveys. There were no personnel centa:nir.ations or overexposures as a result of this event. 5 IV. Safety System Performance and Plant Proximity to Safety Limits f. The reactor vessel head was removed. The Unit I had completed refueling. RHR pump was operating for cavity pumpdown at a flow rate of "A" apprcxicately 675gpm. The "B" RHR pump was operating for core cooling at a flow rate of approximately 3000gpm. Upon indication of cavitation at the "B" RHR pump, the RO realigned the pump to a miniflow lineup and aligr.ed the "A" RHR punp to raise water in the vessel and cavity area. 3 Af ter sufficient cavity-level was regained, the "B" RNR pump was realigned n to resume it's function of core cooling by stabilizing at a flow rate of 1800gpm and then increasing to the TS required flow rate of 3000gpm. Durie.g the transient, the required core cooling was interrupted for a 5 peri:d of approximately 16 minutes. The RCS temperature as read at the disca.arge of the "B" RHR pump increased from 87 degrees F to a peak l L 'l ~,
l l 7 The data recorded in the ERF computer temperature of 107 degrees F. indicated that there was a short period of time during which the "8" RHR l pump discharge pressure was near zero psig. This indicated that the pump j However. may have been running without any flow during this time period. the "B" RHR pump was later verified by the licensee to be operable without having sustained any damage. The RHR pumps at this facility are designed without protection from automatic pump trip when a low suction pressure occurs or on a low flow condition. The pump protection for these conditions is the operation of the pump in a miniflow alignment and
- 1) ERF computer operator actions in response to the following) symptoms: abnormal pump discharg (SPDS) alarm on RHR pump motor instability; 2 The assessment of the flow; and 3) unstable pump discharge pressure.
operability of the "B" RHR pump after the transient is addressed in section IX of this report. Except for the reactor vessel level instrumentation that is used for cavity and vessel pumpdown which was not functioning properly as discussed in section VI!! of this report, all plant safety systems required for these plant conditions were functional. This included the Component Cooling Water system, and the Nuclear Service Water Cooling system from the (ultimate heat sink), RCS makeup capabilities by gravity feed RWST, and the charging pumps. Based on the plant specific data provided in figures 2 and 3 of plant Operations Procedure 18019-C, the staff projected that the estimated tice to RCS saturation was 75 minutes and the estimated time to uncover the l core was 6.S hours under the loss of core cooling condition assuming shutdown cooling flow could not be reestablished. Thus, a sufficient No TS safety margin to any safety limit existed during the transients. Under required safety limits for these plant conditions were exceeded. the plant conditions discussed above, the staff considers that the fuel j I integrity had not been affected during this event. i l V. Procedure Reviews J i Procedures and administrative controls were reviewed to verify that j. exining procedures covered reduced inventory operations, provided precautions and prerequisites for entering into a reduced inventory j condition, and to determine whether existing procedures contributed to this event. 4 The licensee's initial investigation revealed that a collapsed HEPA filter i duct attached to a pressurizer safety valve penetration prevented the pressurizer from being vented to the atmosphere. The HEPA filter was a fan type unit rated at 2000 to 2400 cfm with the capability of maintaining The licensee utilizes a approximately 1.2" wg pressure at 2000 cfm. reactor coolant system sightglass manifold with attachments for a tygon tube as an independent method of determining RCS level during reduced Operation procedures listed in Attachment C, invoie inventory conditions. the requirement that a tygon tube watch be established when RCS level is " 9 Sered telew 15'; oressuri:er level (207 feet) and periodic checks
8 should be made every 4 hours between the control room indication and the tygon tube. The control roo-indicators should be within 7% of scale with the tygon tube. [ The Operations procedures provide guidance that should level be lost or become suspect, to suspend draining operations and resolve problems, and \\( ( if necessary, initiate injection to restore level. However, no ,f instructions were provided directing Operations to veruv that a correct N. tygon tube lineup existed, and to ensure an adequate vent path was \\ 5 established. ~ I Independent level indication is required when the RCS will be depressurized and less than 140 degrees F. Maintenance is directec to connect level indication per raaintenance procedure 54840-1. The procedure provides instructions for installation, fill and leak testing of the sightglass manifold and/or tygon tube, however, it does not include guidance concerning establishment or verification of an adequate vent path. Procedure 54S40-1 was not implemented prior to comencing the RCS draining evolution, nor was any other approved procedure utilized to verify alignment of the independent RCS level indication. VI. Training The training program was reviewed to determine the extent to which the licensee addressed potential difficulties that may occur during reduced inventory conditions; whether related industry events involving loss of cooling during mid-loop operations were covered prior to entering )the current outage; and training materials were reviewed (Attachment C te determine whether they contributed to the apparent loss of shutdown cooling. i The inspector reviewed the licensed and non-licensed operator trainir.g programs, including the continuing training program and reviewed course completion and attendance records. The curriculum provides ample information concerning reduced inventory operations and loss of coolir.g during mid-loop operations. The basic overview lesson of the RHR system, the licensed operator ar.d non-licensed operator lesson plans for the RHR system operations (start up, place in standby readiness, loss of RHR, cavity fill and draining activities)werereviewed. Additionally, reviews of student handouts and l simulator guides coupled with the reviews of instructor lesson plans were l detemined to adequately cover pump cavitation and vortexing phenomena. The training material adequately covered the importance of accurate level i indication for the RCS during draining and mid-loop operation. This area was stressed throughout the training program. Numerous references were made concerning the importance of preventing excessive flow rates, creverting kinked heses. collapsed lines due to vacuum, improcer valve t
l i 1 9 i 3 a lineups, air bubbles, debris in lines, improper routing, temperature of i the fluids, surge line uncovery, and improper syste, flow rates which can j cause inaccurate level indication. Even though the operators received extensive training concerning the ) importance of RCS level indication and all the conditions that can affect RCS level indications, operator interviews revealed that the operators did l l not relate the RCS level indication problems encountered on the October J i 26, 1991, to improper venting. f Vll. Operator Actions Interviews were conducted with the operators involved with the October 26, i 1991 apparent loss of shutdown cooling event. Discussions involved shift i turnover information, verbal directions given to individual operators, what interpretation was given tc the directed activities and the individual's judgement involved in addressing: RHR pump cavitation, and the observed RCS level discrepancies involved with the installed instrumentation, the tygon tube, and the sightglass manifold. i Operator interviews revealed that during the day shift, on October 26, l l. 1991. ECCS testing had been completed, RHR train B was supplying shutdown cooling with train A being used for reactor cavity draining and to support cavity decontamination efforts. The cavity was drained down to 210 feet f rorr 215 feet. The cavity level was monitored certinuously by direct observation by an operator. The operator was in direct comunication with the control room via headset. Subsequently, operations was requested to continue lowering cavity level for further decontamination of cavity walls l and to support weld repairs for indications noted on reactor vessel i flange. 1 The day shif t established a tygon tube watch about ene hour prior to shif t l The i change to support draining the cavity below the 2C7 feet level. l operator establishing the tygon tube watch improperly assumed that the new sightglass modification was turned over to Operations since there were no The clearance tags hanging on valves associated with the new sightglass. clearance tags had been removed iradvertently through other activities in 4 { the area. He did not conduct a walkdown of the new installation nor did he question the control room concerning the operability of the new sightglass modification. The on-coming operator assigned to relieve the tygon tube watch noted that the off-going watch was having difficulty observing any level within the sight glass. Draining was in progress and RCS level was reportedly at 207 feet and decreasing. The level should have been visible at the top of the sightglass. The on-coming operator noted that the sightglass was empty The and promptly reported the condition to the control room operator. control room operator stopped all draining activities and directed the I tygon tube watch to investigate. The tygon tube watch determined that the sightglass was isolated and reported this condition to the control room, stating that the system alignment would be corrected and that the 4
10 Both the off-going and the sightglass would then be filled and vented.on-coming tygon tube wat However, this the valve lineup, and filled and vented "
- auge glass.
task was accomplished without the use of any drawings or procedures to ensure a correct lineup was established. The control room operator actions, when being notified that the sightglass was empty and isolated, were appropriate in stopping all activities However, the operator's associated with draining of the reactor cavity. actions were not appropriate since draining activities were resumed without making a determination of why the sightglass was empty and isolated with a tygon tube watch established. Once the operators aligned the sightglass (one valve was later found to be closed), filled and vented the syste:n, draining was recornenced after determining that levels in the sightglass, tygon tube and reactor cavity The cavity level did net were indicating the same approximate level. appear to be decreasing as quickly as expected for the draining rate in The drain rate was decreased, but the level decrease seemed to A level progress. The draining was stopped to allow level to settle. check between the tygon tube, sightglass and cavity level indicated a increase. level of 194 feet. At about the same time as the level check was being conducted, the high This appeared to have been a reflash level alarm for the RCS alarmed. The control room operator observed that the reactor vessel condition. wide range level gauge (1-LI-957) indicated full and tapped the gauge. The level indication dropped from 100 percent to 60 percent. Operations contacted 14C. The discussion revealed that the instruments had The decision was made historically been unreliable in similar situations. indica tion. Operations that the sightglass was the most reliableAt approximately 193 feet indicated continued draining to 192 feet. level, RHR B pump flow became erratic, flow and pressure went to zero. on minflow. The operator secured shutdown cooling and placed the pump Operations subsequent actions were correct in recovering reactor cavity level and reestablishing shutdown cooling. Cooling was lost for Further investigation by operations found a approximately 16 minutes. collapsed pressurizer vent duct on the instruments' vent poth (comon mode failure for all instruments) and a closed valve (should have been open) between the top of the sightglass and the pressurizer, both of these discrepancies contributed to false RCS level indication on all indicators. l Vill. Reactor Coolant System Water Level Instrumentation The inspectors reviewed the licensee's RCS water level instrumentation to least two independent, continuous determine whether there were at indications of the RCS water level available when the plant was to be operated in a reduced inventory condition. I
11 The licensee had established a visual level indicator (tygon tube) from the bottom of the hot leg to the top of the pressurizer. The connections for this instrument were from the loop 1 intermediate leg to a vent valve on the top of the pressurizer. The tygon tube had a scale of one foot increments. This method of level indication' had been used during outage conditions since initial plant operations. i The licensee had also established an electronic level monitoring system t%t indicated levels in a reduced inventory condition (lower than the vessel flange level). This level indication was displayed in the control The method used to implement this indication was to disconnect the room. normal level instruments from the number 1 and 4 accumulators (1-LT-950 and 1-LT-957) and connect temporary level transmitters to this circuitry. These temporary level instruments are connected to the RVLIS isolators and to pressurizer level transmitter 1-LT-459. The instruments use the accumulator electronics circuits to provide an alarm from 1-LI-950 when reactor vessel level decreases to approximately 187', and an alarn from 1-LT-957 if level increases to a level of 192'(this alarm is nonnally illumir.ated with levels greater than 192'in the vessel and cavity area). } The configuration of both the visual and electronic level indications i being connected to the pressurizer resulted in this being a comon point. As a result, when the HEPA filter was placed on the pressurizer vent point l and a vacuum drawn on the pressurizer, all of the instruments were j affected in a nonconservative direction. In addition, since ESF testing had caused level changes in the cavity and vessel, pumping down out this excess water also added to the vacuum condition since an adequate vent path was not available. Therefore two independent level instruments were not available for this function. IX. Operability of "B" RHR Pump l DurinS this event the "B" RHR pump was observed to experience cavitation on twc separate occasions. The first cavitation occurred at 10:35 p.m. and was approximately three minutes in duration. The second was at 10:59 p.m. and lasted approximately two minutes. Af ter the pump was restored to l normal flow conditions, control room personnel monitored pump running amps 4 and flow for stable conditions. The indications appeared to be normal. j' An operator was dispatched to the "B" RHR pump room to visually inspect the punp. His visual inspection determined that there were no unusual pump noises, vibrations, seal leakage or bearing damage. Based on the observations at the pump and control room indications, operations l personnel determined the pump was safe to continue to operate. On October 28,1991, the licensee initiated several actions to verify that no darage had occurred to the pump. Maintenance technicians took vibration readings at two locations 90 degrees apart near the pump / motor flange. The pump at that time was operating at 3050gpm compared to a flow rate cf 2000gpm which is the normal flow rate that these vibration readings are taken. The readings were 1.3 mils and 1.5 mils. The readings were slightly higher than the previous high readings of 1.0 mils and 0.3 mils (k'estinghouse allows uc to 3 mils for these values.) The
l 12 difference could possibly be attributed to the difference in flow rates at which the readings were taken. Also an IST Senior Engineer, using the October 25 pump operating data, calculated that the pump was operating slightly below the desired point on the pump operating curve but was above the minimum acceptable curve assumed in the safety analysis. Maintenance Engineering personnel also took vibration data readings at six locations on the pump and motor. This data compared favorably with previous historical data dating back to April 1988. None of the six recorded points exceeded the baseline values nor did they approach the warning or alert limit values. Motor current readings were also taken and found to be acceptable. On October 31, the licensee also obtained upper and lower bearing oil samples for analysis. The results of the analysis of these samples indicated no abnonnal conditions in the pump bearings. Due to existing plant conditions the licensee was not able to establish the necessary system alignment to conduct a formal IST on the "B" RHR puep. Procedure 14812-1, Residual Heat Removal pump and Check Valve 157, requires 23 feet of water above the reactor vessel flange for Mode 6 testing. Since the reactor vecsel head was about to be installed and the reactor cavity had been drained, the test was not conducted. The licensee planed to conduct an IST prior to entering Mode 4 in accordance with procedure 14805-1, Residual Heat Removal Pump and Check Valve IST - System
- in Standby.
The licensee consulted Westinghouse concerning potential pump damage as a result of running the pump in the conditions existing at the time of the event. Westinghouse advised that when a pump is operated under adverse j suction pressure conditions, the level of pump damage and the continued i pump operability is best determined by inspection and testing of the pump. j They advised the licensee to rotate the pump shaft by hand and to vent the 4 pump casing prior to operation. In addition, during subsequent operation, visual observation for leakage should be conducted to confirm that the pump seal is not damaged. Vibration levels, pump head and motor amperage should be monitored during operation. They further stated that if these values meet the surveillance requirements, this would confirm that the pump suffered no internal damage that will affect the pump hydraulic performance or operability. On November 1, after the linit had entered Mode 5, the licensee performed procedure 14812-1 for the "B" RHR pump. The measured data from that surveillance were within the acceptable range and the performance of the "B" RHR pump was considered satisfactory. l
i. 4 13 - ] X. Sightglass Modification The design and installation of the Unit 1 RCS level indicating sightglass was controlled under DCP 91-VIN 0150-0-1. The purpose of the DCP was to replace the original sightglass which had been installed during the second i refueling and which was determined to be an unacceptable design. Operations had expressed a preference for a continuous level indication spanning from the pressurizer heaters to the bottom of the hot leg. This type of sightglass had been installed on Unit 2 during the last refueling and the intent was to duplicate that design on Unit 1. The design incorporated a flexible, clear plastic hose as the sightglass to measure l the RCS water level during draindown and reduced inventory or mid-loop 1 operations in the region between the bottom of the pressurizer and the l bottom of the hot legs. 's At the time of this event, the sightglass modification was essentially complete. All that remained to be done was a scale adjustment and the 1 performance of a functional test. Maintenance was still holding the Nd0 j paperwork since the scale had not been set. The sightglass had been tagged out by operations, however, one of the hold tags at the bottom of j the sightglass was missing. The system engineer responsible for the i modification had not yet completed a RTS form to be placed with the { Modification tog located in the Control Room. Thus, the Control Roor. had not been notified in writing that the modification had been completed and that the system was ready to be used. XI. Generjcletter88-17 Actions GPC responded to GL 88-17 in correspondence dated December 29, 1988. In 4 this correspondence with respect to providing two independent, continuous j RCS water level indications whenever the RCS is in a reduced inventory condition, the licensee responded as follows: RCS water level is monitored via temporary level instrumentation whenever the RCS in a reduced inventory condition. Operations procedures include instructions to notify Instre:r.cntation and Control personnel to install temporary level instruments prior to draining the RCS. Instrusntation and Control Procedure 23985-1, "RCS Temporary Water Level System", provides instruc-tions for installation of two independent channels of level indication using temporary transmitters and existing levels instrumentation in the control room. 3 l Level is measured directly from the hot leg between the RVLIS upper range lower tap and the pressurizer steam space to minimize thermodynamic and pressure errors. l~ One channel provides wide range level indication from approximately one foot below mid-loop to the vessel flange. The other channel provides narrow range level indication from approximately one foot below mid-loop to the top of the hot leg. Level is continuously monitored .... i... ?
14 in addition to the temporary level transmitters, a tygon tube is installed per Procedure 54890-1, " Installation and Removal Instructions for the RCS Water Level Tube". The tygon tube is used as a backup to be continuously monitored when operating below 17% pressurizer level, if either control room indication is lost or while reducing RCS level. GPC believes that this reconnendation is appropriately addressed, and no further action is planned. The NRC reviewed the response and in correspondence to GPC dated January 27, 1989, the NRC stated that the staff had reviewed the submittal and found that is generally met the intentions of the generic letter with respect to expeditious actions and is adequate for plant operation. This letter also identified areas that were incomplete, however, the response associated with level indications was not questioned. l NRC review of the GL 88-17 implementation is addressed in NRC Inspection Report Nos. 50-424/89-19 and 50-425/89-23. Although the reactor vessel level indicating system was connected to the RCS as stated in their correspondence for the electronic level instrumentation, the licensee did not provide a description of the tygon tube system which was the backup for the electronic system. Since all of l this instrumentation had a corinon reference into the pressurizer, all level instruments would be affected by perturbations in the pressurizer. The system installed does not ' meet the intent of two independent continuous water level indications as discussed in GL 88-17. XII. Human Performance Implications A. Introduction The team reviewed control room and local control instrumentation used by the operators during the drain down evolution to determine if the indications available to the operators may have contributed to the event. The team determined that the Control Room instrumentation, operator i aids, and local RCS level indications used by the operators during the drain down evolution were readily accessible, adequately labelled, and adequately scaled for the activities associated with the planned evolutions. The temporary modification of the control rcom accumulator tank level gauges and annunciator windows for RCS level indication were understood by the reactor operators. Although annunciator window for ALB-06-003, " Accumulator #4 Hi/Lo Level", associated with temporary RCS level indicator 1-LI-957, had not been modified to read "RCS High Level" prior to the event, the operators understood that the annuniciator was associated with RCS level. The addition of temporary operator aid PTDB-1, "Mid-loop Level
_ _.. _ _ _ _ _ _. _. _ _ _ _ _ _.. ~_ l 1 i 15 l Instrumentation Unit 1", to control panel 1A1, provided the operators l with a useful tool for conversion of control room RCS level indication from level as a percentage (".) to level in feet. This helped provide consistency with the local RCS level indications which j were scaled in feet (temporary tygon tube) and in both feet and l inches (sightglass). j The team considered additional aspects of human performance which may have contributed to this event. The team reviewed a sample of the licensee's administrative controls and operating procedures. l interviewed plant Operations personnel, and walked down local RCS 1 level indication systens. As a result, the team determined that the human performance aspects which contributed most significantly to l this event include: (1) miscommunication between control room crew and plant equipment operators in the containment; (2) weakness in design control practices; and (3) weaknesses in procedural implecentation. An Event and Causal Factors Chart has been prepared to cid in the understanding )of the human performance implications of this eve (see Figure 4. From the chart, it becomes evident that several causal factors contributed to most of the' events leading up to the RHR pump cavitation. The team has attempted to characterize the human factor implications outlined in this chart. B. Contributing Causes The team determined that se'veral causal factors contributed to the failure of the operating crew to realize the actual RCS level and to understand the factors which may have contributed to the erroneous RCS level indications. Human errors are seldom the result of a single root cause, and as described below, this investigation identified several facters which together contributed to the event. 4 1. Communications The day-shift auxiliary operator was instructed by the control room supervisor to monitor the tygon tube. The USS, knowing the sightglass had not been returned to service, expected the APO to monitor the temperary tygon tube according to his instructions. The APO reported to the 185' level of the contain6.ent building and upon seeing the sightglass believed he should monitor that system, and proceeded to do so. During shift turnover, a second APO was requested to relieve the opcator at the tygon tube. When the second APO arrived at the sightglass, he assumed the system had been returned to service, since the APO already at J the location was monitoring the device. The second APO did i realize that the sightglass was empty and called the Control Room to report the ccnditon. Af ter consultation with the Control Room, the AP0s proceeded to fill and vent the system in an attempt to place it in operation. j
a. 16 These activities were characterized by a lack of explicit instruction to the AP0s dispatched to monitor local RCS level as to which indicator was to be used. In addition, the AP0s and control room operators did not fully consider or question their supervision as to why the sightglass was isolated prior to i placing it into operation. These comunication breakdowns contributed to the use of unauthorized and inappropriate plant equipment for monitoring RCS level. 2. Design Control Practices The team reviewed the design control process and observed several weaknesses in this process and its implementation of the sightglass modification. Administrative controls for the implementation and closure of Design Change Packages are provided in procedure 50008-C, DCP Implementation and Closure. The procedure specifies that a J Return to Service (RTS) Checklist shall be completed by the j responsible engineer and presented to the USS for notification prior to declaring the system operable. The USS may then, at his discretion, declare the system operable or wait for 3 additional activities to be completed, if such additional activities are required. The methods used by 'the USS to notify operations personnel of the status of system operability may include: (1) discussion during shift turnover briefings; (2) inclusion in crew required reading books if the modification affects procedures; (3) general crew discussions; (4) or for insignificant modifications, may not warrant any discussion among the crew at all. However, these methods are informal, and do not. appear to be governed by sufficient administrative control to ensure that all plant personnel affected by modifications would be notified s of such changes. The design control process allows for the removal of clearance tags on equipment for functional testing prior to returning the equipment to service. This process, as noted by the team during walkdown of the sightglass modification, may create a situation where plant personnel could mistakenly implement equipment not returned to service because of a lack of clearance tags or other indications on the equipment. As a result of the evaluation of this event, the AP0's dispatched to locally monitor RCS level indication did not observe any clearance tags on the sightglass or lewer boundary isolation valve (HIH) and, therefore, assumed th:1 the equipment had been returned to service. The lower valve had been previously tagged but the tag had apparently fallen off. 1
17 3. Procedural Factors Procedural guidance on the installation and use of the sightglass indicator is provided in procedure 54840-1, RCS Draindown Modifications: RCS Sightglass, Tygon Tube, and Defeat of RHR Suction Yalve Auto Closure Interlock. This procedure was not, at the time of the event, released to operations because the sightglass had not yet been functionally tested and returned The operators dispatched to locally monitor RCS to service. level attempted to place the' system in operation without the As a result, the appropriate procedure or valve lineup sheet. operators did not realize that an upper boundary isolation valve (HIL) had been installed during the modification and therefore Had failed to open this valve and align the system correctly. the operators attented to open valve HIL, they would have seen a clearance tag or. the valve and may have questioned the use of the sightglass for r.onitoring RCS level. j in addition, the team determined that the operating procedures used during the craindown (U0P-12000-C) did not require the sightglass to be walked down prior to use to ensure proper alignment and a ver.t path. If the operators had walked down the l entire system before starting to monitor RCS level, they may have observed the clearance tag on the upper isolation valve and j questioned the use of the sightglass. If the sightglass had been completely walked down prior tu operation, the operators l would probably have noted the HEPA filter installed on the pressurizer and notified the Control Rcom operators of the l collapsed hose. XIII. Reportability The licensee considered tne reportability of this event in accordance with 10CFR50.72 at 10:35 p.m. on October 26. Vogtle procedure 9100-C l did not identify any condition that would result in imediate i notification of the NRC. At about 2:00 a.m. on October 27, the SS contacted the Operatior.s Unit Superintendent to discuss the ever.t. i They concluded that since the "B" RHR pump was not secured in i ~ response to the cavitation problem and that the cavitation did stop when flow was reduced, and the "A" pump was also available and did not cavitate when used to add water to the vessel, a complete loss of cooling did not occur. They decided that a report in accordance with 10CFR50.73 was not required. l. At 6:30 a.m. that morning the Assistant General Manager - Operations l was notified. He contacted the General Manager and Vice President. Since the decision was.-ade that this'was not reportable, management decided to establish an event review team to further review this event, submit a voluntary LER, and notify the re ident inspectors. i The team reviewed this issue during the inspection and concluded that the even.t. sh.o.uld. hav.e..:. ten reported to.,the NRC in accordance with .g y,,,
) i 18 conditions that the "B" RHR pump was removed from service due to a cavitation problem and had the "A" RHR pucp been placed in operation - under the existing conditions, it would have experienced a similar i problem. i The licensee contacted the Team Leader on November 6, and notified him that upon further analysis indications existed that the "A" RHR Based on that information pump was exhibiting signs of degradation. the licensee notified the NRC in accordance with 10CFR50.72. In addition, the licensee identified that their analysis had shown that water level had decreased to slightly belew the nozzle centerline (187'). This was based on the point that was predicted for vortexing Their conclusion was the pump could not pump at a 4 on the "A" pump. flow rate of 3000gpm and, therefore, it could not meet the definition of operability. The licensee also identified that calculations indicated that temperature could have reached a maximum of 116 degrees coolant temperature and 117 degrees fuel temperature assuming no cooling was available during the transient. During the period of time that the RHR pumps were not available other makeup to the vessel from the RWST and a charging pump was available. Gravity feed from the RWST could have been utilized if necessary at a flow rate of approximately 1000gpm to refill and cool the vessel. a XIV. Conclusions The Team made the following conclusions during the review of this event: 1. Sufficient safety margin existed during the event. No TS safety limits were exceeded and fuel integrity was not affected. 2. Operations staff took prompt action to quickly assess the problem and reestablish shutdown cooling. 3. Design and installation procedures for visual level indication and electronic level instrumentation were inadequate in that independency was not implemented as part of these indicators. This resulted in a comron mode failure for all level instrun.ents 1 monitoring reactor vessel level. 4 The licensee did not ;erform an adequate evaluation concerning the reportability of tnis event. 5. The system for control of modifications in progress is weak in that inadequate means were available to indicate the sightglass system was not available for operator use. 6. The system used to control temporary codifications is weak in that there are no requirements to perform an analysis for connecting HEPA filters to safety related systems.
l;- 19 7. Comunications were weak between the operators in the control room and the APO's in containment in that it was not made clear which indication was required to be monitored. In addition, when notified of the sightglass being isolated and empty, control room operators did not stop te question this condition. 8. Operations procedures provide adequate guidance that should level be lost or become suspect, to suspend draining operations and resolve the problem. However, no directions were provided in these procedures directing operators to verify correct tygon tube lineup existed, and to ensure an adequate vent path for the instrumentation. 9. Training materials were adequate to cover the event in progress. Al though this material was provided during the training sessions, the operators did not relate this problem to the training they had been given. XIV. Exit Interview With Licensee Management The inspection scope and findings were sumarized on November 1, 1991, with those persons indicated in Appendix A. The NRC described the areas inspected and discussed in detail the inspection results delineated in this report. No proprietary material is contained in this report. No dissenting comer.ts were received from the licensee. i
20 APPENDIX A - PERSONS CONTACTED i Licensee Employees
- J Bailey, Manager Licensing SNC
- H. Beacher, Sr. Engineer Technical Support i
- J. Beasley, Assisstant General Manager Operations W. Brack, Auxiliary Plant Operator i
G. Brenenborg, Health Physics Supervisor i
- J. Brown, Acting Training Manager i
- W. Burmeister, Manager Engineering Support D. Carter, Shift Superintendent M. Chance, Sr. Plant Engineer -
- S. Chesnut. Manager Technical Support
- C. Christiansen, Supervisor SAER W. Diehl, Unit Shift Supervisor j
G. Durrence, Plant Operator B. Evans, Plant Operator T. Forehand,' Plant Engineer
- J. Gasser, Unit Superintendent Operations
- H. Handfinger, Manager Maintenance T. Hargis, Shift Superintendent M. Henry, Auxiliary Plant Operator M. Hickon, Sr. Engineer
- M. Hobbs, ! & C Superintendent
- K. Holmes, Manager Chemistry and Health Physics G.. Hooper, Plant Engineering Supervisor J. Hopkins, Shift Superintendent P. Humphrey, Reactor Operator C. Hutton, Plant Equipment Operator
- W. Kitchens, Assisstant General Manager Support
- R. LeGrand, Manager Operations M. Lewis, Reactor Operator
- G. McCarley, ISEG Supervisor
- K. McCoy, Vice President
- C. Meyer, Operations Superintendent K. Middlebrooks, Unit Shift Superintendent W. Mitchell, Auxiliary Plant Operator A. Nix, Plant Equipment Operator
- R. Odom, Plant Engineering Supervisor i
T. Polito Unit Shift Superintendent R. Reece, Reactor Operator
- M. Sheibani, NSAC Supervisor L
- W. Shipman, General Manager
- W. Smith, Sr. Engineer Technical Support
'C. Stirespring. Manager Plant Administration j
- J. Swartzwelder, Manager Outage and Planning i
S. White, Unit Shift Superintendent l J Other Personnel m v ,,s -4. - - - -
i i 21 APPEhDlX B ACRONYMS AIT Augmented Inspection Team APO Auxiliary Plant Operator AOP Abnormal Operating Procedure DCP Design Change Package i ECCS Emergency Core Cooling System i ERF Emergency Response Facility I&C Instrumentation and Control l ISEG Independent Safety Engineering Group i gpm Gallons Per Minute HEPA High Efficiency Particulate Absorber HP Health Physics 1 IST Inservice Test LER Licensee Event Report MW Megawatt MWO Maintenance Work Order NRC Nuclear Regulatory Conr.ission NSAC huclear Safety and Compliance 1 PE0 Plant Equipment Operator RCS Reactor Coolant System R0 Reactor Operator RHR Residual Heat Removal RTS Release to Service RWST Refueling Water Storage Tank SAER Safety Audit and Engineering Review SPDS Safety Parameter Display System SS Shift Supervisor TS Technical Specificatiors i i UOP Unit Operating Procedure USS Unit Shift Supervisor VEGP Vogtle Electric Generating Plant wg Water gauge
i 22 APPENDIX C j l DOCUMENTS REVIEWED A. Procedures 17006 1 ANNUNICI ATOR RESPONSE PROCEDURE FOR ALB-06 ON PANEL 1A2 ON MC8 i 14812-1 RESIDUAL HEAT REMOYAL PUMP AND CHECK VALVE IST 14805-1 RESIDUAL HEAT REMOVAL PUMP AND CHECK VALVE IST - SYSTEM IN STAND 8Y 12000-C, Rev. 18, POST REFUELING OPERATIONS (MODE 6 TO 5) i 12006-C, Rev. 20, UNIT COOLDOWN TO COLD SHUTDOWN I 12007-C, Rev. 20, REFUELING OPERATIONS (MODE S TO MODE 6) 12008-C, Rev. 2, N10-LOOP OPERATIONS 13011-1, Rev. 25, RESIDUAL HEAT REMOVAL SYSTEM 13005-1, Rev. IS, REACTOR COOLANT SYSTEM DRAINING 14000-1, Rev. 31, OPERATIONS SHIFT AND DAILY SURVEILLANCE LOG 18019-C, Rev. 10 LOSS OF RESIOUAL HEAT REMOVAL (MID LOOP LOCA) ( f 23985-1, Rev. 3 RCS TEMPORARY WATER LEVEL SYSTEM i 54840-1, Rev. 4, "RCS DRAINDOWN MODIFICATIONS: RCS SIGHTGLASS, TYGON TUBE, AND DEFEAT OF RHR SUCTION VALVE AUTO CLOSURE l INTERLOCK" 8. TRAINING PATERIALS REVIEWED LO-LP-12101-24-C, Rev. 24 RHR SYSTEM LO-LP-60315-08-C, REV. 8 LOSS OF RESIDUAL HEAT REMOVAL 4 i LO-LP-61212-01-C, REY. 1 MID LOOP OPERATIONS LO-lU-60315-001-C, REY. 4 RESPOND TO LOSS OF RESIDUAL HEAT REMOVAL
23 i LO-lU-12101-004', REY. 3 ORAIN REFUELING CAVITY LO-1U-12101-005, REV.1 RESPOND TO RHR SYSTEM ALARMS LO-H0-12101-002-C, REY. 5 LOSS OF RHR. INDUSTRY EVENTS LO-SE-60266-00, REV. O INTEGRATED RESPONSE -' REQUAL NL-!U-12101-001, REY. 1 PREPARE RHR SYSTEM FOR OPERATION NL-lu-12101-002, REV. 2 DRAIN REACTOR REFUELING CAVITY USING RHR SYSTEM RQ-HO-12111-001-00, REY. O RHR AND MID-LOOP OPERATION RQ-HO-09001-01, REY. 2 CYCS SYSTEM RQ-HO-37101-001-C, REY. 0 ECP REVISION !! i i RQ-HO-12111-001, REY. 1 RHR AND MID-LOOP OPERATION RQ-LP-63113 00, REV. O RECCAL C'.'RRENT EVENTS 4 i l
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