ML20129H972
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,1 ENCLOSURE 3
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION September 17, 1991 5
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UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION l
l OFFICE OF NUCLEAR REACTOR REGULATIONS l
DR. THOMAS E. MURLEY, DIRECTOR i
In the Matter of
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GEORGIA POWER COMPANY, et al.
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Docket Nos. 50-321,
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50-366, l-(Vogtle Electric Generating Plant,
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50-424, l
Units 1 and 2)
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and 50-425
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(Hatch Nuclear Plant,
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(10 CFR 2.206) l Units 1 and 2)
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PARTIAL DIRECTOR'8 DECISION PUR8UANT TO 10 CFR 2.206 i
i INTRODUCTION j
j On September 11, 1990, Michael D. Kohn, Esq. filed with the l
Nuclear Regulatory Commission (NRC) a " Request For Proceedings j
and Imposition of Civil Penalties for Improperly Transferring Control of Georgia Power Company's Licenses to the SONOPCO j
Project and For the Unsafe and Improper Operation of Georgia Power Company Licensed Facilities" (Petition) on behalf of i
Messrs..Marvin B. Hobby and Allen L. Mosbaugh (Petitioners).
The Petition was referred to the Office of Nuclear Reactor Regulation (NRR) for the preparation of a Director's Decision in accordance with 10 CFR Section 2.206 by the Director of NRR.
Exhibits in support of the Petition were received on September 21, 1990 and a supplement to the Petition was received on October 1, 1990.
The Petitioners are former employees of Georgia Power Company (GPC or licensee) which holds licenses from the NRC for the operation of a number of nuclear facilities, including the Vogtle facility.
The Petitioners made a number of allegations regarding the management of the GPC nuclear facilities.
Specifically, the Petition alleged illegal transfer by GPC of its operating licenses to Southern Nuclear Operating Company (SONOPCO), knowing misrepresentations by GPC in responding to concerns of a commissioner regarding the chain of command for the f
Vogtle facility, intentional false statements to the NRC 206DEC2.
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regarding the reliability of a diesel generator whose failure had resulted in a Site Area Emergency at Vogtle, perjured testimony j.
submitted by a GPC executive during the course of a Department of Labor (DOL) proceeding under Section 210 of the' Energy i
Reorganization Act, repeated abuse at the Vogtle Facility'of Technical Specification 3.0.3, repeated willful Technical i
specification violations at the Vogtle facility, repeated i.
concealment of safeguards problems from the NRC, operation of the radioactive waste systems and facilities at Vogtle in gross violation of NRC requirements, and the routine use at GPC nuclear facilities of non-conservative and questionable management i
practices.
The Petitioners sought the institution of proceedings I
and swift and immediate action by the NRC based on these j
allegations.
l On October 23, 1990, I acknowledged receipt of the Petition and concluded that no immediate action was necessary regarding these matters.
That determination was based on completed and ongoing NRC inspections and investigations of the licensee and particularly of the operation of the Vogtle facility.
I further informed the Petitioners that a Director's Decision regarding i
these matters would be issued within a reasonable time.
On February 28, 1991, the NRC requested that the licensee j
respond to the Petition.
The licensee responded on April 1, j
1991.
On July 8, 1991, Petitioners submitted " Amendments to Petitioners Marvin Hobby's and Allen Mosbaugh's September 11, 1
1990 Petition; and Response to Georgia Power Company's April 1, 1991 Submission by its Executive Vice President, Mr. R. P.
Mcdonald" (Supplement).
The Supplement alleged that GPC's Executive Vice President made material falso statements in GPC's April 1, 1991 submittal to the NRC.
The Supplement also alleged that this same individual made false statements to the NRC at a transcribed meeting held on January 11, 1991 held to discuss the formation and operation of SONOPCO.
The Supplement also provided additional information with regard to certain allegations made in the earlier Petition.
The Supplement requested a variety of relief including a request that the NRC take immediate steps to determine whether GPC's current mariagement has the requisite character and competence to continue operating a nuclear facility.
On August 26, 1991, I acknowledged receipt of the Supplement, and informed the Petitioners that I had determined that no immediate action was appropriate and that the specific issues raised in the Supplement would be considered in my Director's Decision.
On August 22, 1991, the NRC requested the 206DEC2.
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licensee to respond to the Supplement.
The licensee submitted j
its response on September __, 1991.
When referencing specific issues raised in the petition, I.
l have elected to use a numbering system corresponding to that in the original Petition of September 11, 1990.
For example, a 4
i reference to. issue number "III.6c" in this Decision would i
correspond to the issue found in Section III, paragraph 6, F
subparagraph c, of the original Petition.
Most of the issues in the Petition are identified within Section III, entitled " Facts."
However, two items mentioned in my Decision are from Section II of the Petition, entitled " Background of Petitioner."
i Some of these issues will not be addressed in this Decision.
l I do not, at this time, address' allegations of discrimination raised by the Petitioners that are before the Department of i
i Labor.
The NRC and the DOL have agreed to coordinate and cooperate concerning the employee protection provisions of j
Section 210 of the Energy Reorganization Act of 1974.
Generally, i
when a complaint has been filed with the DOL alleging j
discrimination by an NRC licensee, the NRC defers its consideration of the matter until the DOL has acted.
This policy avoids. duplication of effort and needless expense of resources.
The NRC mCintains regular communications with DOL associated with this issue to assure that current activities are monitored and appropriate action can be taken when required.
Nor am I prepared to make a determination for certain issues regarding wrongdoing raised by the Petitioner.
These will require further. investigation by the Commission's Office of Investigations (OI) before I can determine what action, if any, is appropriate.
These issues currently are being addressed within OI.
I do address in this Decision those issues alleging wrongdoing for which the facts are presently understood a's a result of NRC inspections or other revicws such that no investigation is needed.
Finally, I do not address the allegations in Section III.9 of the Petition because these issues are of a summary nature, drawing their basis from specific allegations presented earlier in the Petition.
Because the earlier allegations in'the Petition are not yet addressed, my decision for these summary allegations must also be deferred.
For all issues not addressed today, when OI's effort and the DOL proceedings are complete, I intend to issue a supplement to this Decision.
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DISCUSSION i
i Petitioners have raised a large number of issues in their l
submittals.
Many of these issues are still under consideration i
by the NRC Staff and will require additional time.before conclusions can be reached.
The NRC Staff has completed its d
i review of a number'of the issues and conclusions havt been l-reached.
consequently, I have determined to issue a Fartial Director's Decision with regard to those issues which are capable
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of final resolution now.
My. discussion and Decision with regard i
to such issues follow.
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II.b Mr. Mosbaugh states that he was removed from the Plant Review Board (PRB) by the vogtle Plant General Manager j
j after he attempted to resolve safety issues with the PRB.
j Response to Section II.b l
Mr. Moscaugh was temporarily placed in the position of Assistant General Manager - Plant Support (AGM-PS) during the i
1989-1990 time frame, while the permanent AGM-PS was completing j
the training program to obtain his Senior Reactor Operator (SRO) license.
Prior to this time, M.T.
Mosbaugh was the Assistant i
Plant Support Manager.
The perLanent AGM-PM training program was i
known to be of limited duration (approximately one year).
Mr.
Mosbaugh's assignment to the position was also known to be
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-limited to the period during which the permanent AGM-PM was in the licensing program.
t PRB membership is specified in Vogtle Technical i
Specification 6.4.1, and Vogtle Administrative Procedure 00002-C, "PRB Duties and Responsibilities."
In both of these documents, membership is designated by organizational position, not by name.
The position of AGM-PS is designated as a member of the PRB.
Upon completion of his training, the permanent AGM-PS was given the temporary assignment of Unit 1 Refueling Manager.
During the Unit 1 refueling outage, several other senior members of the Vogtle management staff were given this special assignment.
The purpose of this assignment was to provide a 24-hour per day management presence at the site during the refueling outage in order to improve the timeliness of decision-making and to ensure that an appropriate level of managerial expertise was 206DEC2.
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available to assist in maintaining adherence to the outage activities.
i The Unit 1 outage ended April 14, 1990.
Due to difficulties i
experienced by the plant in reaching and maintaining full power 4
operation, it was not until May 14, 1990 that the AGM-PS assumed j
his permanent position.
Concurrent with this action, he re-I assumed his duties as a voting member of the PRB.
Based on the NRC review of this issue at this time, the evidence does not support that Mr. Mosbaugh's removal from the PRB was related to his attempts to obtain resolution of safety l
issues.
Instead, the timing appears to be coincidental with the return of the permanent AGM-PS to his position.
Since Mr.
i Mosbaugh had been bringing up items he considered to be safety.
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issues for a significant period of time prior to his removal, and given that the AGM-PS had completed his SRO licensing for at i
least 3 months prior to his return to his permanent position, if retribution had been the motive for Mr. Mosbaugh's removal fron the PRB,.this action would likely have been accomplished as soon l
as the permanent AGM-PS was out of his training status.
- Instead, i
the personnel actions which had been previously planned and were understood by all of the concerned parties were allowed to take j
place.
When the permanent AGM-PS resumed his permanent position, j
he assumed all of the ancillary assignments (e.g., PRB membership) with it.
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III.1 Petitioners alleg's an illegal transfer of licenses to 80NOPCO l
Response to Section III.1 H
To understand this issue, it is necessary to first review l
the history and background regarding the formation of SONOPCO.
The SONOPCO project was established by Southern Company for.
l the long-term purpose of establishing an operating company j
(Southern Nuclear Operating Company or SONOPCO) to operate the l
nuclear power generating plants licensed to operate by Georgia l
Power Company (GPC) and Alabama Power Company (APC).
There were several steps in this process which were to be accomplished in three major phazes, with SONOPCO project first providing support 1
services to the operating companies (GPC and APC), and ultimately
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transferring the operating licenses to SONOPCO.
Because of delays, the project moved slower than anticipated and remained in the initial project phase for about 2 years (1989 and 1990).
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Phase 1 was the establishment of the SONOPCO project, with Mr.
Farley' responsible for the administrative aspects of the formation of the new operating company.
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The GPC nuclear facilities were to remain under the
~ direction of the GPC President, Mr. Dahlberg, with a reporting i
chain downwards of Executive Vice President (Mr.-Mcdonald),
Senior Vice President (Mr. Hairston) and Site Vice Presidents for the Hatch and.Vogtle facilities.
The'APC plants were to remain under the direction of the APC President, with a similar chain downward of Mr. Mcdonald, Mr. Hairston, and a Site Vice President
- for the Farley station.
Mr. Mcdonald and Mr. Hairston were j
officers of both APC and GPC.
l' In Phase 1, technical support was provided to all three l
l nuclear facilities by a common Technical Services group under a Vice President of Southern Company Services who reported to the Executive Vice President, Mr. Mcdonald.
This phase-was to be effective until permission was obtained from the Securities and Exchange Commission to establish SONOPCO.
Mr. Farley was not designated as having any responsibility for the GPC nuclear i
facilities during this phase.
He was responsible for establish-l ing the legal entity of SONOPCO.
It was generally presumed that l
Mr. Farley was to become the President and CEO of the new corporation when it was established.
Phase 1 began about November 1, 1988.
The Petition alleges that during this time l
frame, GIN: improperly transferred control of its nuclear licenses l
to SONOPCO.
I Phase 2 began in January 1991, with the establishment of SONOPCO as a legal entity.
As part of this phase, the Executive Vice President and Senior Vice President, Nuclear Operations I
(Messrs. Mcdonald and Hairston) would also become officers of SONOPCO and report administratively to the President and CEO of l
SONOPCO.
The Vice Presidents of each nuclear facility would also i
become officers of SONOPCO.
The Vice President of Technical Services would become an officer of SONOPCO, rather than be an Officer of Southern Services Company.
During this phase, GPC and l
APC would retain the licenses and responsibility for their
- respective nuclear facilities.
The 2.206 Petition predates the beginning of Phase 2.
Therefore, the control of GPC nuclear j
facilities during this phase is moot with respect to the i
Petition.
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Phase 3,.when SONOPCO has operating responsibility, will i
j begin when the licenses for GPC and APC nuclear facilities have i
been transferred to SONOPCO.
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l DRA W ECI520 MAL-INFORMAh 4N Petitioners claim that during Phase 1 of the transition to l
SONOPCO, GPC transferred control of its licenses to SONOPCO project.
They claim evidence to support their Petition was l
obtained as a result of their. witnessing the day-to-day operation i
of GPC's nuclear facilities at the site and at GPC's corporate j
offices.
Petitioners claim that "the actual chain of command was i
General Plant Manager George Bockhold (Vogtle) to SONOPCO Vice President McCoy; McCoy to SONOPCO's Senior Vice President, George l
Hairston, Hairston to SONOPCO's Executive Vice President and Chief Operations Officer, R. Patrick Mcdonald; Mcdonald to SONOPCO's Chief Executive officer, Mr. Farley".
In a supplementary filing dated October 1, 1990, petitioners further claimed that Mr. Farley, " chose the GPC Corporate Officers which would be staffing the SONOPCO project even though he is not an officer or employee.of GPC".
In March 1988, GPC and APC met with NRC to discuss their plans.for the formation of a separate operating company, SONOPCO.
NRC met with GPC on July 25, 1988, to discuss the SONOPCO/GPC corporate organization including generic activities and initiatives involving the Vogtle and Hatch facilities.
Enclosure 3 to the meeting summary prepared by Region II dated August 11, 1988, a Nuclear Operations-Transition Organization chart, shows the Vice President-Nuclear (Hatch), and Vice President-Nuclear (Vogtle) reporting to Mr. W. G. Hairston, Senior Vice President-Nuclear Operations and Mr. W. G. Hairston reporting to Mr. R.P.
Mcdonald, Executive Vice President-Nuclear Operations.
Previously, on March 1, 1988, Mr. Mcdonald was elected a senior officer of GPC and named Executive Vice President-Nuclear effective April 25, 1988, and on May 4, 1988, Mr. W. G. Hairston was elected Senior Vice President-Nuclear Operations of GPC and Mr. C. K. McCoy was elected Vice President of GPC (GPC submittal April 1, 1991, Attachment 1, Exhibit 4).
In early November 1988, Phase 1 of the transition began.
During the period December 19-21, 1988, the NRC conducted an.
inspection of the corporate organization, responsibilities, and functions at Birmingham, Alabama (Inspection Report Nos. 50-321/88-41, 50-366/88-41, 50-424/88-60, 50-425/88-77, 50-348/88-33, and 50-364/88-33).
Part 3 of this report states:
"In preparation for combining the management of Vogtle, Hatch, and Farley into one organization, GPC has reorganized and moved the corporate nuclear operations to Birmingham...
Currently, the Executive Vice President and Senior Vice President for Nuclear Operations are officers of both GPC 206DEC2.
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and APC... The Vice Presidents for each of the three l
projects (Vogtle, Hatch, and Farley) report to the Senior Vice President of Nuclear Operations."
The transcripts for the Department of Labor Proceeding of j-Hobby vs. GPC, (fall 1990) indicate that Mr. Dahlberg (GPC President) stated that Mr. Mcdonald takes all his management direction from him with respect to the operation of GPC's nuclear plants; the operation of GPC's nuclear facilities report directly to him; and for management operations dealing with GPC plants, Mr. Mcdonald reports to him (Proceeding Transcripts at 305, 307, j
and 309).
Mr. Farley stated that he does not have any responsibility for the operation of GPC's nuclear facilities and
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i Mr. Mcdonald does not report to him with respect to the operation of Hatch and Vogtle.
(Proceeding transcripts at 567 and 568).
'Mr. Mcdonald stated that he reports to Mr. Dahlberg with respect l
to the operation of GPC's nuclear facilities (Proceeding-Transcripts at pages 613 and 614).
l In a deposition of May 5, 1990, at pages 13 and 14, Mr.
Mcdonald stated that he had no reporting responsibilities to Mr.
Farley.
Mr. F. D. Williams, in a memorandum to Mr. H. B. Hobby, j
dated May 15, 1989, stated "Mr. R. P. Mcdonald reports to A. W.
j Dahlberg for operation and support activities of Plants Vogtle j
and Hatch.
I have attached a copy of the most recent published l
organization chart showing the reporting.
Mr. George Hairston j
reports to Mr. Mcdonald".
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There is no direct evidence to support the claim that Mr.
Mcdonald reported to Mr. Farley with respect to the operation of the Hatch or Vogtle nuclear facilities.
Mr. Hobby acknowledged
.that he had no personal knowledg4 that Mr. Mcdonald received his i
direction from Mr. Farley (Hobby vs. Georgic Power Company, transcript at page 239).
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The depositions and testimony do provide some support to the l
contention that Mr. Farley participated to some degree in the selection of personnel for the SONOPCO project, including some of j
those who were also elected as GPC corporate officers.
As Mr.
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.Farley was responsible for formation of SONOPCO, and was expected f
to become its President and CEO, this is not unususl.
Such i
selection of personnel does not conflict with license requirements, provided personnel in the operating organization 4
meet NRC requirements with respect to qualification, a condition not at issue here.
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l The Petition expresses specific concern that the Executive Vice President - Nuclear Operations was taking guidance and direction from the SONOPCO organization, as opposed to the GPC l
CEO.
Review of the Vogtle Final Safety Analysis Report, the Vogtle license, and records of a special inspection conducted to l
review the SONOPCO management organization, indicated that the I-responsibility for decisions affecting the operation of the plant rests with-the Senior Vice President - Nuclear.
I find, based on 3
facts stated above,'that during the period in question (Phase 1),
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the chain of command for the Vogtle and Hatch facilities was from their respective Site Vice Presidents to Mr. Hairston.
Mr.
Hairston reported to Mr. Mcdonald, who reported.to Mr. Dahlberg, President of GPC.
Because all of these individuals are elected officers of GPC and the reporting chain is to the President of GPC, I conclude that there has been no transfer of responsibility-from GPC for the Vogtle or Hatch facilities.
III.2 Petitioners state that GPC misled the Commission about the chain of command from the Vogtle project's Plant Manager to its CEO.
Response to Section III.2 On March 30, 1989, the Commissioners met to discuss and possibly vote on the full power operating license for VEGP Unit 2.
The transcript reflects that then Commissioner Carr expressed concern about the hierarchy between the Vogtle plant manager (i.e., the general manager) and the Chief Executive Officer (CEO), noting that it " looked to me like he was a long way from the CEO."
Mr. R. P. Mcdonald, GPC Executive Vice President -
Nuclear Operations, responded that (1) he (Mr. Mcdonald) reported to Mr. Bill Dahlberg, the GPC CEO, (2) that Mr. Ken McCoy, Vice President of Vogtle, reported to him (Mr. Mcdonald), and (3) that Mr. George Bockhold, then Vogtle general manager, reported directly to Mr. McCoy.
At the conclusion of the meeting, the commissioners voted unanimously in favor of the license, and the license was issued the following day.
On May 1, 1989, Mr. W. G. Hairston, III, Senior Vice President for Nuclear Operation, forwarded to the NRC a letter of correction of the transcript, noting that Mr. Mcdonald had
" inadvertently left out the Senior Vice President of Nuclear Operations.
The organization is as described on figures 13.1.1-1 and 13.1.1-2 of the Vogtle Final Safety Analysis Report."
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'The Petition claims that Mr. Mcdonald knowingly made false
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i statements to the NRC Commissioners in the presence of Messrs.
Dahlberg, McCoy, and Bockhold during his response to then i
Commissioner Carr in that he " eliminated one entire level of management between the plant manager ind the CEO."
Moreover, the 4
i Petition asserts that " Messrs. Dahlberg, McCoy and Bockhold i
should have known that Mr. Mcdonald's statements 1were false'and l
should have b7ought this to the immediate attention of the i
Commission and otherwise corrected the record before the l
Commission acted on the Vogtle full power license request."
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Mr. Mcdonald responded to the Petition on April 1, 1991.
The response _noted that the Commission had been apprised of the i
Company's organization prior to the March 30th proceeding, including the Senior Vice President position, by an amendment to the_VEGP Final Safety Analysis Report (FSAR) that was submitted Novemb6r 23, 1988.
The amendment described the reporting chain j
from Mr. McJoy to Mr. Hairston to Mr. Mcdonald.
Mr. Mcdonald's
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response also stated that the NRC had reviewed the organizational structure in December, 1988, and. issued an inspection report.
i The inspection report stated that the Vice Presidents of the Farley,. Hatch and Vogtle facilities reported to the Senior Vice i
President who, in turn, reported to the Executive Vice President, i
and that the organization was consistent with the Vogtle FSAR l
j amendment submitted in November, 1988.
The reply by Mr. Mcdonald also noted that during the March 30th proceeding, Commissioner Rogers referred to the fact that he I
had-reviewed the company's organizational chart during a visit he j
had made to the plant site.
1 The written response by Mr. Mcdonald to the Petition also notes that the letter of correction of the transcript was made l
i approximately two weeks after receiving the NRC transcript.
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The NRC staff has reviewed this issue and has concluded that
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the omission was likely significant in that the reply was in j
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direct response to the commissioner's stated concern for an l-organizational structure in which the plant manager appeared to be "a long way from the CEO."
The staff has also concluded that Mr. Mcdonald's reply to then Commissioner carr was inaccurate in that the transcribed record was clearly in contradiction with j
other documents of record, including the FSAR and NRC Inspection i
Reports.
In view of the prior knowledge of those present regarding the documents and NRC reviews of record, the staff 3
j concluded that Mr. Mcdonald's omission was obvious to many j
licensee representatives and NRC personnel present during the
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i meeting. 'Because the omission of Mr. Hairston was considered by l
those present to be obvious, it was not corrected at the tinte.
.Under the circumstances, a deliberate attempt to mislead the l
Commissioners seems highly unlikely and the staff concludes, therefore, that the omission was unintentional.
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i From my review of this' issue, including the supporting l
documents forwarded by the Petitioners and the licensee, I agree i
with the NRC staff's position summarized above.
Moreover, I agree that inaccurate information was given to the Commissioners, j
but I. disagree with the Petitioners that it was deliberate.
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also agree that enforcement action is not appropriate.
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III.5 Petitioners allege that SONOPCO routinely threatens the safe @)esgg3cn of GPC's nuclear facilities by allowing them to and34 Technical specification (TS) 3.0.3, j
referred go in the Petition as " motherhood".
The j
Petitioners also allege.that the SONOPCO did not make the required notifications to the NRC when TS 3.0.3 was J
entered.
I Response to Section III.5 The NRC has concluded, based on various inspections conducted by region-based inspections and through observations by the permanently assigned resident inspection staff, that GPC does i
not routinely enter into TS 3.0.3.
l Vogtle TS 3.0.3 requires that, when a limiting condition for operation (LCO) is not met, except as provided in the associated action requirements, action shall be taken within 1 i
hour to place the unit in a mode in which the TS does not apply by placing it in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, in hot l
shutdown within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and at least in cold shutdown within the subsequent 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The purpose of TS 3.0.3 is to ensure a timely and orderly i
shutdown of the reactor plant is accomplished when the specific j
LCO is exceeded, or a condition exists that is not addressed by i
TS requirements.
As long as the final action is accomplished within the time frame specified in the TS,.then the TS is ll -
satisfied.
If the condition requiring entry into TS 3.0.3 is i
corrected prior to commencing or completing the shutdown, then the shutdown may be terminated and the plant returned to previous j
conditions.
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j As documented in NRC Inspection Report 50-424,,425/90-19, dated January 11, 1991, GPC management.had indicated that actions for an orderly shutdown would not be initiated until at least 3
. hours after entry into TS 3.0.3.
In addition, GPC managemant 1
indicated that an orderly, controlled shutdown could be l
accomplished within one hour, if need be. ~ GPC has. interpreted j
the action statement of TS 3.0.3 to allow 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> to be in hot standby, and to accomplish this, the shift could wait for at l
least 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after. entering the LCO before commencing a wereunderthesecircumstances.patnoimmediate shutdown.
GPC's position was t notifications i
GPC actions in this area were j.
not significantly different from that of various other licensees with the exception that GPC takes no immediate actions to notify i
the-load dispatcher and written guidance had not been provided to the operations personnel.
As a result of this being identified L
as a weakness in the inspection report, GPC has provided written i
guidance to the operators for use upon. entering TS 3.0.3.
This guidance, issued February 28, 1991, has been reviewed by the NRC 5
j and found to be acceptable.
The specific example identified by the petitioners with t
regard to this issue concerned the Licensee's practice in the area of emergency diesel generator safety-related load i
sequencers.
Petitioners claim that the lic<tnses failed to i
recognize that the loss of a load sequencer resulted in the entry I
into TS 3.0.3 and, thus, required notification to the NRC.
i There are two Engineering Safety Feature Actuation System (ESFAS) sequencers for each unit required to be operable during Mode.1, 2,
3, and 4.
The NRC and GPC personnel determined that i
the removal of the load sequencers from service could result in j
entering the LCO for TS 3.0.3 or TS Table 3.3-2 depending on what i
portion of the sequencer system was removed; some of the circuits were included in Table 3.3-2 but the remainder of the system was 4
l not addressed by TS.
The Operations Department had historically I
i The NRC confirmed that while adherence to the actions l
discussed in Generic Letter 87-09 (i.e., notification of the load dispatcher within the first hour and performance of a controlled i
shutdown throughout the next 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 7) was not done, there were no i
instances where the 7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> time limit to be in hot. standby was j
exceeded.
Additionally, there was no indication that the load dispatcher had been notified in any of these instances that a 3
. change in plant operation had been initiated.
This finding was i
I identified as a weakness in Inspection Report 50-424,425/90-19.
206DEC2.
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linked load sequencer outages to the emergency diesel generator f:
(EDG) LCO of TS 3.8.1.1.b (78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> to hot standby).
Although the applicability of TS Table 3.3-2 and TS 3.0.3 to sequencer outages had been recently identified, discussions with the 4'
licensee indicated that past load sequencer outages had not been reviewed by the licensee. 'The NRC has conducted a review of i
completed Maintenance Work Orders (MWO) which were performed on
{
i the sequencers on Units 1 and 2, as well as the related surveillance tests by the Instrumentation and Control- (IEC),
Engineering, and Operations Departments.
Several instances were 1
identified where the work performed would have required the load l
sequencers to be de-energized.
However, the associated unit was found not to have been in Modes 1, 2,
3, or 4 at the time this
{
work was performed and thus no TS LCO's applied.
i Similar to the NWO review, a review of related'IEC, d
Engineering, and Operations Department's surveillance tests did not find any examples of the load sequencers having been de-l energized while in Modes 1 through 4.
j If a load sequencer is not operable, the more restrictive' i
requirement of TS 3.0.3 and TS Table 3.3-2 are applicable.
The
{-
concern of exceeding the LCO for TS 3.0.3 or TS Table 3.3-2 when the load sequencers were previously de-energized was not j
confirmed.
i The entry into TS 3.0.3 did not require NRC notification j
specified in 10.CFR 50.72 since in each case no reduction in
{
power was necessary.
However, 10 CFR 50.73 requires a Licensee i
Event Report to be submitted when entry into TS 3.0.3 is i
necessary.
Since GPC did not recognize they were in TS 3.0.3, no i
reports. ware made pursuant to 10 CFR 50.73.
Under the NRC l
Enforcement Policy, a licensee is not normally cited for a failure to report a condition or event of which the licensee was not aware.
Accordingly, the NRC has concluded that GPC does not routinely threaten the safe operation of VEGP by allowing entry I
into TS 3.0.3.
Petitioners claim that NRC notification requirements were violated are not substantiated.
III.6 Petitioners claim that SONOPOO routinely endangers the public's safety by ignoring Technical specification, i
and that this is illustrated, in part, by the following
{
examples
)
206DEC2.
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III.6.b On February 26, 1990, the NRC found that dilution j
valves required to be locked closed were not locked i
while at "mid-loop" in violation of TS.
Petitioners t
assert that this is another example of willful violation of Technical Specifications by Vogtle senior j
management.
4 l
III.6.c Procedural errors made by two shifts of licensed operators miscalculated the shutdown margin for Vogtle Unit 1 which was shutdown at the time.
A i
W III 6.e.iii i-SONOPCO knowingly concealed a T8 violation when "B" RER 3
pump was not declared inoperable after cracking of NsCW water cooling line and "A" RER pump was inoperable due to outage work.
j Response to Section III.6.b On February 26, 1990, while Unit 1 was in Mode 5 with reactor coolant loops not filled (mid-loop), the NRC identified that discharge valve, 1-1208-U4-176, from the Refueling Makeup l
Water Storage Tank (RMWST) was closed but was not mechanically i
secured as required by TS 3.4.1.4.2C.
Instead of a mechanism to mechanically secure this valve, the valve had a clearance hold i
tag which provided only administrative control to preclude valva l
operation.
At the time this condition was pointed out by the
~
NRC, VEGP personnel contended that the administrative controls were acceptable to fulfill the requirements,of the TS.
Upon i
further discussions, VEGP agreed that this method was not acceptable and took action to install a mechanical, lockable device.
The NRC did not consider this to be a willful violation of TS since the administrative controls provided some means of i
control and this appeared to be an isolated casar The NRC issued j
Violation 50-424,425/90-05-01,
" Failure to Mechanically Secure
{
Valve 1-1208-U4-176 During Mode 5 As Required By TS 3.4.1.4.2.C."
206DEC2.
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During a subsequent NRC Inspection (Inspection Report 50-
)
424,425/91-14), this violation was reviewed and closed.
The inspectors reviewed the locked valve procedure, 10019-C, which
-had been revised to eliminate utilization of a " hold tag" on j
valves that are required by TS to be secured in position.
For the valve which resulted in this violation, a steel cable had s
been routed through drilled holes in the valve handle and then l_
mechanically secured to. prevent operation of the valve. -The licensee conducted a comprehensive review of all remaining valves which are required by TS to be secured to ensure that a locking l
j mechanism was in place.
The licensee committed to provide an appropriate locking mechanism for those valves, if any, which are J
4 secured by hold tags and are required to be secured by TS.
l.
However, no other valves were identified which fell into that category.
e i
Response to Section III.6.c I
At 5:35 pm on January 19, 1989, control room operators at Vogtle manually tripped the Unit 1 turbine and reactor to enter a planned outage to repair a leaking socket veld on the pressurizer, i
loop seal safety relief valve drain.
After the unit was shut j
down, an extra shift supervisor on shift completed _ Procedure 14005-1, " Shutdown Margin Calculation," which is required to be
)
completed every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when in Modes 3, 4, or 5.
He signed the l
i procedure at 7:13 pm on January 19, 1989.
The extra shift supervisor, however, incorrectly completed Data Sheet 2, which applies to conditions when the average reactor coolant system i
temperature is equal to or greater than 557 degrees Fahrenheit.
l This action was incorrect as he should have completed Data Sheet 4, which applied to conditions related to entering Cold Shutdown (Mode 5).
That shutdown margin calculation, using the wrong data sheet, resulted in a calculated shutdown margin of 6.6% delta k/k and a required shutdown margin of 2.58% delta k/k.
These results 7
indicated to the operators that no boron addition to the RCS was j
required in order to enter Cold Shutdown.
l-l On January 20, 1989, at approximately 9:00 an, a reactor
[
engineer questioned the apparently low RCS boron concentration of 1333 ppa.'
Due to his concern, the unit cooldown was stopped i
until the shutdown margin calculation was verified.
At 10:22 an the reactor engineer completed a shutdown margin calculation that
[
assumed a RCS temperature of 68 degrees Fahrenheit and o pcm Xenon worth.
His calculation, without taking credit for Xenon i
worth, showed that 1800 ppa boron concentration was necessary to j
obtain a shutdown margin of 4.015% delta k/k compared to,a l
206DEC2.
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l required shutdown margin of 3.47% delta k/k.
It should be noted l
again that no credit was taken for Xenon worth which would have l
added approximately 3.8% delta k/k to the shutdown margin and l
provided more than an adequate margin above Technical Specification requirements without further boration.
Since no Technical Specification limit was exceeded, the licensee did not j
submit a report to the NRC.
On January 20, 1989 at 1:38 pm, the On-Shift Operations Supervisor recalculated the shutdown margin which had been l
incorrectly determined at 7:13 pm on January 19, 1991.
The new l
calculation used plant data in effect on January 19 and was based upon Data Sheet 4.
The new calculation determined that the i
shutdown margin was 4.185% delta k/k compared to the required j
shutdown margin of 1.92% delta k/k.
The NRC Resident Inspectors reviewed Procedure 14005-1, Data i
Sheets 2 and 4, the calculations concerning the data sheets dated l
January 19-20, 1989, and control room logs for that time period.
The shutdown margin calculation performed at 7:13 pm on January 19, 1989 was incorrect in that the wrong Data Sheet of Procedure 14005-1 was used.
However, there was no evidence to suggest that Technical Specification limits on shutdown margin were ever l
exceeded or that an inadvertent criticality would have occurred 1
due to the use of the wrong data sheet.
A factor contributing to l
the error was the confusing instructions on Data Sheet 2 of Procedure 14005-1.
That procedur.e was subsequently revised on j
March 26, 1989, to simplify, consolidate and clarify the data j
sheets.
It should also be noted that the licensee failed to write a deficiency card for this event which would have prompted a licensee followup review of the error.
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Response to Section III.6.e.iii l
The petitioners allege that during Unit l's second refueling l
outage (1R2), with residual heat removal (RHR) Train A out of.
l service for maintenance, the Train B RHR pump experienced excessive vibration and the nuclear service cooling water (NSCW) i l
motor cooler experienced a leak at its outlet.
TS 3.9.8.1, "RHR and coolant Circulation," was allegedly violated because the a
Operations Department chose not to declare RHR pump 1B inoperable in an effort to mitigate the impact on the critical work path.
This item was included in the special team inspection discussed in Supplement 1 to NRC Inspection Report 50-424,425/90-19, dated September _, 1991.
As noted in Section 2.2 on the j
Inspection Report, the NRC concluded that the Operations i
j 206DEC2.
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dIMI IBT'R3 0TLON p MO M OR J BLIC RELEASE DRAFT --PREDECISIONAL INFORMATI Department had an adequate engineering basis for accepting the operability of the RHR pump in spite of the pump's high vibration i
pnd the NSCW leak.
In addition, the inspection team concluded that declaring the pump-inoperable would not have impacted the
' critical work path: the LCO actions would.not have been restrictive because the containment, except for ventilation, had pean isolated as required by TS 3.9.4.
The LCO actions would not have prevented the continuation of refueling activities because the actions to close all containment penetrations providing i
direct access from the containment atmosphere to the outside i
j atmosphere would only have required closing the containment 4
. ventilation purge valve which has an automatic closure signal.,
j l
Thus, any suggestion that schedule could have motivated the j
licensee in this matter was not warranted.
1 1
The NRC inspection did identify that the licensee violated the station's administrative procedures by failing to initiate a deficiency card for either the NSCW outlet leak or the excessive l
vibration of the RNR motor as requ1 red by Operations Procedure j
j 00150-C. Enforcement action in accordance with the Enforcement Policy is being considered.
i III.8 Petitioners assert that SONOPCO has endangered the '
{
public's health and safety by operating radioactive waste systems and facilities known to be in gross j
violation of NRC requirements.
Petitioners also state j
that Vogtle8s General Manager intimidated members of i
the (Plant Review Board) PRB when they attempted.to consider whether the waste system should be resumed.
'1 l-Response to Section III.8 f
Petitioners allege that GPC installed and operated a radwaste micro-filtration system, known as the FAVA system, I
without performing an adequate engineering and safety evaluation l
(i.e., 10 CFR 50.59).
Petitioners further allege that the material configuration, fabrication and quality of the system did j
not meet the guidance of Regulatory Guide (RG) 1.143 and-the requirements of the American Society of Mechanical Engineer's (ASME) Code.
In late 1987, a system had been temporarily installed and operated at Vogtle for removing Niobium-95.
GPC planned to replace this temporary modification with a permanent, high-i quality, system in the future.
li.
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In February 1988, GPC experienced difficulty with the temporary system in removing colloidal Niobium-95 following a i
reactor shutdown for maintenance work.
FAVA Control Systems
]
(FAVA) was contracted to help rectify this problem.
The i
situation was-corrected by installing a 0.35-micron filter system downstream of the existing pre-filters.
However, a large l.
volume of radwasts was generated as the 0.35-micron filters i
rapidly exhibited high differential pressure and were required to be changed frequently.
The need to change filters frequently also rer.ulted in additional radiation exposuru to Radwaste l
Department personnel.
i
[
Upon evaluation of the performance of the 0.35 micron filter system, the Radwaste Department felt that the best approach to j
the problem was a back-flush, pre-coat filter system.
- However, no operational data was available for a system of this type in-l this specific application.
FAVA supplied a proprietary Ultra Filtration System (Model No. 5FD/E) for testing purposes in order to evaluate whether or not this was a viable and economic solution to the problem.
The FAVA system was installed before i
the Unit i refueling outage and was operated under Test Procedure i
T-OPER-8801.
The test system kept liquid affluent releases well below TS limits.
On the basis of an evaluation of test resulta j
by the Radwaste, Chemistry, and Engineering Departments, a general work order was initiated to purchase a permanent system.
i l
In the early part of 1989, a Quality Assurance (QA)
Department audit identified a significant audit finding involving a programmatic breakdown in the procurement of the FAVA system and a failure to meet commitments of the Final Safety Analysis Report (FSAR).
Because of that finding, the FAVA system was removed from service.
In late 1989, the licensee sought to reinstall the FAVA system under a temporary modification because colloidal cobalt-j 59 and Cobalt-60 had to be removed.
The Plant Review Board (PRB) reviewed this temporary modification and several members expressed strong objections to it ba ad on the previous QA audit finding.
i In response to this, a request for engineering assistance (REA) was submitted and a 10 CFR 50.59 safety evaluation was performed in late 1989.
The licenseets engineering staff identified that the safety evaluation did not properly address i
the guidance of Regulatory Guide (RG) 1.143 regarding the use of
}
polyvinyl chloride (PVC) piping.
Therefore, another safety
^
evaluation was performed in February 1990 to address this issue, 206DEC2.
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-DRAFT - PREDECIS NAL INFORMATION-i particularly with respect to radiation degradation.
i The February 1090' safety evaluation specifically stated that j
the FAVA system did not conform to the criteria of RG 1.143.
i However, this deviation was found to be acceptable.
Although the testimony of one of the PRB members indicated j
that the temperature effects on the use of PVC in the FAVA System were not adequately evaluated before the system was installed,.
the testimony of the corporate system engineer indicated that F
this was considered prior to installation, although not specifically documented in the safety evaluation.
VEGP management subsequently consulted the NRC resident
. inspector to seek an NRC position with regard to. placing this l
system back in service.
This was supplemented with additional information provided by other VEGP management personnel 4
documenting reasons why it should not be placed in service.
This j -
package was forwarded to Region II and the~ Office of Nuclear Reactor Regulation (NRR) for review.
In March 1990, following
,i-Region II and NRR concurrence via a telephone conference, the j
licensee placed the FAVA system in service with NRC stipulations.
The licensee has complied with the NRC stipulations.
In June 1990, in response-to item 4 (above), the licensee revised Part G of the safety evaluation for the FAVA system.
Part G of the safety evaluation addressed the effect that operation of the FAVA system would have on the probability of occurrence or consequences'of accidents described in the FSAR.
4 j
Although there was no comparable accident analysis in the FSAR i
that addressed alternate radwaste building (ARB) accidents or the i.
consequences of accidents in the ARB, the FSAR accident analyses (Chapters 15.7.2 and 15.7.3) did describe worst-case releases of i
the contents of the recycle holdup tank (NUT).
l The first bounding analysis in Chapter 15.7.2 addressed the j
release of the entire gaseous radioactive contents of the HUT to l_
the environment at ground level and the second bounding analysis i
addressed the release of the entire liquid contents of the HUT i
through an assumed crack in the ARB floor directly into the j
ground water supply.
In both cases, the 10 CFR Part 100 and 10 CFR Part 20 limits were not exceeded.
These criteria were consistent with criteria provided in NRC Circular 80-18, "10 CFR 50.59 Safety Evaluations for Changes to Radioactive Wasta j
Treatment System."
However,.neither of these analyses addressed i
the potential for wall spray down and leakage through the ARB walls and the subsequent release path to the environment.
206DEC2.
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k i
LIMITED MI.8TRIBUTION W R PUBLIC 3(LEASE DRAFT - PREDECISIONAL INFORMATION Therefore, the licensee revised the safety evaluation in June i
1990 to address the conseqv.ances of a hose break on the FAVA system which would result in wall spray down and potential leakage to the environmar.t.
t i
Review of the revised Part G of the safety evaluation l
identified several erroneous assumptions with respect to the release path and the dilution volumes that could be used in the analysis of a hose break and resultant wall spray down.
- However, it was also found.that tus design of the FAVA system (i.e., the use of a system cover) would prevent wall spray down and that the i
only potential source for wall spray down and subsequent leakage was from a hose break in another radwaste system in the ARB.
l Therefore, it was concluded that,the FAVA system safety i
evaluation dated June 1990, adequately addressed the temporary j
modification for the installation of the FAVA system.
t
]
Based upon the above facts, I agree that.the FAVA system was f
originally installed and operated without an adequate safety evaluation and did not meet the guidance in RG 1.143 in that j
polyvinyl chloride (PVC) piping was used in this system.
However, this deficiency was of limited duration as subsequent safety evaluations performed by the licensee concluded that the system was acceptable for use.
Petitioners also contend that Vogtle's General Manager intimidated and pressured Plant Review Board (PRB) wambers during a PRB meeting.
The meeting occurred in February 1990, to determine the acceptability of the safety analysis for the
~
installation of the FAVA micro-filtration system.
As previously noted, several safety evaluations were performed for the temporary modification which installed the FAVA micro-filtration system.
Discussions with PRB members indicated that, during the review of these safety evaluations, various PRB members expressed reservations on several occasions concerning the acceptability of the installation of the system.
Despite these expressed reservations, review by the NRC of the PRB Meeting minutes associated with this temporary modification identified few instances of the PRB members documenting their dissenting opinions.
Specifically, PRB m3eting 90-15 (dated' February 8, 1990) documented one PRB member's negative vote and dissenting opinions regarding the acceptability of exempting the temporary modification from regulatory requirements and the adequacy of the system's safety evaluation.
PRB Meeting 90-28, dated March 1, 1990, indicated that 206DEC2.
21
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DRART - PREDECISIONAL INFORNATION N
1 information and issues regarding the FAVA system's safety analysis were presented to the PRB and that the General Manager solicited written comments and questions from other members for resolution.
The only other example of a dissenting opinion was in PRB meeting 90-32, dated March 6, 1990.
This dissenting 4
i opinion related to the acceptability of voting on the FAVA system l
installation when the PRB member who raised the initial questions i
and concerns on the operation of the FAVA system was not present.
l Testimony from savaral of the PRB members indicated that, j
during the various PRB meetings concerning the installation of the FA" cvstem, the PRB members did feel intimidated and j
pressut
.y the presence of the General Manager at the PRB l
meeting in one occasion, an alternate voting member felt i
intimida
' and feared retribution or retaliation because the
{
General
.:ager was present at the meeting and the PRB member j
knew the General Manager wanted to have the temporary modification approved.
However, the testimony also indicated i
that the PRB member stated that he did not alter his vote and i
felt comfortable with how he had voted.
In addition, this PRB j
member stated that he was not aware of any occasions on which he i
or any other PRB member had succumbed to intimidation or feared j
retribution.
l The General Manager was informed, following the meeting (PRB 90-32), that several PRB members viewed his presence as intimidating.
As a result, on March 1, 1990, the General Manager i
met with all PRB members'to reiterate the member's duties and j
responsibilities.
He specifically told the members that his j
presence at PRB meetings must n9t influence them and that i
alternates should be selected who would feel comfortable with this responsibility.
He also addressed the difference between professional differences of opinion and safety or quality j
concerns, and their respective methods for resolution.
i Accordingly, I find that an investigation by the NRC has identified that, in one case, a PRB voting member felt intimidated and feared retribution because the General Manager was present at the PRB meeting.
However, this member stated that i
he did not change his vote in response to this pressure.
He i
stated that the General Manager w&w informed of this issue and
{
met with the PRB to allay fears.
Based on the testimony obtained by the NRC, it appears that retribution did not occur.
The event j
was confirmed and the absence of dissenting opinions in the PRB meeting minutes indicates that there was a potential for an i
adverse affect on open discussions at the meeting.
Further discussions with PRB members indicated the reason for the lack of 206DEC2.
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dissenting opinions was that items are discussed and reviewed i
until all members were comfortable with their decisions.
}
CONCLUSION For reasons given above, certain issues raised by the Petitioners are deferred pending further investigation'by the NRC or further determinations by the Department of Labor.
Based on the review of the issues which are considered herein, no I
unauthorized transfer of the Vogtle operating licenses has occurred and operation of GPC nuclear facilities is in accordance with NRC regulations and does not endanger the health and safety j
of the public.
The issues addressed in this Decision do not call into question the licensee's character, competence, fundamental trustworthiness and commitment to safety to operate a nuclear facility.
Consequently, I decline to take the actions requested i
by the Petitioners with respect to these issues.
To this extent, j
Petitioner's request for action pursuant to 10 CFR 2.206 is i
denied.
As provided in 10 CFR 2.206(c), a copy of this Decision l
will be filed with the Secretary for the Commission's review.
}
Thomas E. Murley, Director j
Office of Nuclear. Reactor j
Regulation Dated at Rockville, Maryland, this th day of September 1991.
206DEC2.
23 l
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September 17, 1991 LIMITED-DISTRIBUTION - NOT FOR,.10BLIC RELEASE DRAFT - PREDBCISIONAL INFORMATION dissenting opinions was that items are discussed and reviewed
- l until all members were comfortable with their decisions.
CONCLUSION l
For reasons given above, certain issues raised by the Petitioners are deferred pending further investigation by the NRC or further determinations by the Department of Labor.
Based on the review:of the issues which are considered herein, no I
unauthorized transfer of the Vogtle operating licenses has occurred and operation of GPC nuclear facilities is in accordance with NRC regulations and does not endanger the health and safety of the public.
The issues addressed in this Decision do not call into question the licensee's character, competence, fundamental trustworthiness and commitment to safety to operate a nuclear facility.
Consequently, I decline to take the actions requested l
by the Petitioners with respect to these issues.
To this extent, Petitioner's request for action pursuant to 10 CFR 2.206 is denied.
As provided in 10 CFR 2.206(c), a copy of this Decision will be filed with the Secretary for the Commission's review.
Thomas E. Murley, Director Office of Nuclear Reactor Regulation i
Dated at Rockville, Maryland, this th day of September 1991.
LA:PDII-3 PM:PDII-3 D:PDII-3 D:DLPQ D:OI LBerry DHood DMatthews JRoe BHayes
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PC Document Name: PC:206DEC2
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206DEC2.
24
GEORGIA POWER COMPANY VOGTLE NUCLEAR ORGANIZATION N
PRESIDENT & CEO GEORGIA POWER A. W. Dahlberg x
x i
EXECUTIVE VP R. P. Mcdonald x
x N
SENIOR VP W. G. Hairston ill x
x N
VP - VOGTLE C. K. McCoy e
x
""' N N
N GENERAL MANAGER
^
^
~
GENERAL MANAGER NUCLEAR SUPPORT W. B. Shipman (VACANT)
M. Ajiluni x
x x
x x
SAER SUPERVISOR C. Christenson J
0 h l~l h1E
GEORGIA POWER COMPANY VOGTLE NUCLEAR ORGANIZATION l
GENERAL MANAGER W. B. Shipman s
s ASST GENERAL MGR ASST GENERAL MGR PLANT OPERATIONS PLANT SUPPORT l
J. B. Beasley W. F. Kitchens s
s MGR OPERATIONS NUCLEAR R. L. LeGrand SECURITY MGR l
D. Huyck MGR MAINTENANCE MGR ENG &
H. M. Handfinger TECH SUPPORT S. H. Chestnut j
s MGR OUTAGE MGR ENG AND PLANNING SUPPORT J. F. Swartzwelder M. W. Horton MGR HP AND CHEM MGR PLANT K. R. Holmes ADMINISTRATION
{
C. P. Stinespring MGR PLANT TRAINING & EP l
(VACANT) 9 f l'l I
e f -
OPERATIONS MANAGER s
1
. Responsible for Plant OPERATIONS. SUPT
.$[,*,",*4 On Shift (SRO) at.elins.
-Intilal Esners. Coord.
i Unit 1 Unit 2 Shin Supt.
Shin Supt.
Cleerence & Togging i
(SRO)
(SRO)
(Operations Support)
Unit Operation (SAME AS OTHER OE
^
.sa Responsibility UNIT) 1.n o 2 er 3 PEO
. Responsible br tagging of eesaponents for taintenanse & lasting
- Reacter Operator (RO)
Ha*Paa.sbas be op ration.
surveillance testing Responsible for Reacter controls & NSS
_ Rescler Operater (RO)
Res porse l bl e for BO P opernelorse
_ Ptsat Equip. Oper. (3)
Responsible for in plant operatione se directed by SRO's & RO's O
j
VOGTLE ORGANIZATIONAL STRUCTURE October 11-13, 1988 M s een I
s BOCKHOLD General Manager s
j s
BELLAMY Plant Manager KITCHENS Ops. Manager s
s
~
MARSH Asst. Ops. Mgr.
(Similar for 3 Shifts) l l
s s
s CASH HOPKINS OSOS OSOS OSOS s
s s
m s
s s
s s
s s
(Similar to other shin)
(Similar to other shin)
- Reactor Operators (2)
- PE0's (3)
- RYAN Support Shift Superv.
i
TABLE 6.2-1 MINIMUM SHIFT CREW COMPOSITION TWO UNITS WITH A COMMON CONTROL ROOM POSITION NUMBER OF INDIVIDUALS REQUIRED TO FILL POSITION BOTH UNITS IN BOTH UNITS IN ONE UNIT IN MODE 1, 2, MODE 1, 2, 3, MODE 5 or 6 3, cr 4 AND ONE UNIT IN or 4 OR DEFUELED MODE 5 or 6 or DEFUELED OS 1
1 1
SRO 1
none**
1 R0
-3*
2*
3*
NLO 3*
3*
3*
STA 1***
none 1***
05 - Operations Supervisor with a Senior Operator license SRO - Individual with a Senior Operator license RO - Individual with an Operator license NLO - Non-Licensed Operator STA - Shift Technical Advisor The shift crew composition may be one less than the minimum requirements of Table 6.2-1 for a period of time not to exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements of Table 6.2-1.
This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift crewman being late or absent.
During any absence of the Operations Supervisor from the control room while either unit is in MODE 1, 2, 3, or 4, an individual with a valid Senior Operator license shall be designated to assume the control room command function.
During any absence of the Operations Supervisor from the control room while either unit is in MODE 5 or 6, an individual with a valid Senior Operator license or Operator license shall be designated to assume the control room command function.
- At least one of the required individuals must be assigned to the designated position for each unit.
- At least one licensed Senior Operator or Licensed Senior Operator Limited to Fuel Handling who has no other concurrent responsibilities must be present during CORE ALTERATIONS on either unit.
V0GTLE UNITS - 1 & 2 6-5
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Mr. Kitchen 1.
Your submittal as well as the one made by GPC discussed at length the 4
role of the SRO: in the sequence of events under discussion.
If you i
~ would, please discuss the role and views (if you know them) of the other licensed operators on the two shifts.
If he answers that he understood they were not involved ask him as operations manager was he surprised that R0s would not know of entry into the TS and chem add / dilution of the primary plant, what possible reasons were for not involving them?
2.
Turning to your deliberations on the TS when you completed your l
researchontheTSandthedefinitionofimmediatewasanydocumentation formal or informal made of it?
Why not?
e l
Why wasn't your management involved, especially.since you put a hold on a critical path item. Why wasn't the onsite review comittee or the NRC contacted?
j Following us on the last question, putting aside how pro i
3.
was as to wto you got involved in the TS interpretation,per your decisioncould tell us how and why this evolution proceeded with both a TS interpretation from the ops Manager and without an approved procedure for the chemical addition in this configuration?
Here again why weren't others contacted?.
Can you recall.any other occasion when this happened?
(TS interpretation and using strictly clearances to perform an evolution?)
4.
Your response to the Demand for Information states that there was no personal advantage for you to willfully violate the TS at issue (if we assume for the discussion that you knew the TS prohibited your actions). Given that the chemical addition was a critical path item whose approval would you have needed to skip it?
Wouldn't it have been at least enbarrassing to admit that it could not be done as scheduled?
Wouldn't there be inersased radiological problems?
Did you consider what the impact would be on the schedule if you had refilled the loops to perfonn the evolution?
.. ~
. _.. ~ -
,,a.....,
O i?
2 s
Kitchen Response no 2 Itr My general knowledge of boron dilution event and my earlier 1987 i
experience relative to the meaning of immediate in a different action stdat lead me to conclude that the valves could be opened j
no more than 15 minutes.
i
/
4 Do 3 ltr FSAR provisions confirmed my view that TS 3.4.1.4.2 purpose was to place admin controls on valves not to prohibit opening.
Da 4 it Elimination of hydrogen peroxide addition would have shortened schedule.
82
{
gg_.1 Shift would like concurrence that addition of H 0 by opening RMWST valves was acceptable (10/12/88) approx. 5 a.m.
John Hopkins j
(oncoming OSOS) + Unit Shift Supv. - operators viewed evolution as a bit unusual but no major controversy.
i Ag_1 TS 3.0.2 defines NC as "when the requirements of the LCO and Action Statements are not met within the specified time frame.
3 gg_(
FSAR 15.4.6.2.1.2 - did not know until.9/26/89 that not analyzed for mode 5, loops not filled also read 15.4.6.2.2.2 and d
15.4.6.2.2.1.
f
. gg 1 FSAR 9.3.4.1.2.5.14 states chen mix tank preparation for corrosion-product pidation during a refueling S/D.
pg_Z The12/86amendmenttoFSARdidnotadequatElyreviseSection15 i
to state that chem addition in mode 5 LNF no longer encompassed in analysis.
1 gg_1Q Chemical cleaning was not vitally important.
l 4
- S Eg*
i-i 4
i 1
L -
4 I
Bowles ResDonse Unit Shift Supervisor DQ l ltr approved procedures had been reviewed for regulatory Compliance plZ 2
DC 2 Itr I Was either unaware that N injection into the SGs had in fact occurred or unaware that such injection drained primary water in the generators. Had I known the plant was in a " loops not filled" condition the possibility exists that I would have questioned the applicability of TS 3.4.1.4.2.
Oncoming SS informed me that he believed the plant was or would be in a " loops not filled condition."
PL1 I did not attend planning meetings since I was on shift, consisting of 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> work days.
4 The shift briefing at turnover would have been the first instance that I knew my responsibilities as SS included overall responsibility for the chemical cleaning evolution.
pl.1 If I had known the TS applied I would have discussed the matter with Ops Dept Mgmt before proceeding since voluntary entrance into an LC0 which requires "immediate" action would be unique and novel.
p.g 4 Lack of awareness of TS applicability was caused by my inexperience and lack of guidance in that I had an imprecise understanding of the term "mid-loop" and " loops not filled." I also did not fully appreciatg the actual condition of the RCS, i.e., that the addition of N into the primary side of the SGs placed the Unit in a " loops not. filled" condition.
psJ Either did not know that Na had been added to SG during his shift or did not recognize its significance. Did not understand the SG draining evolution.
~ * ~ ~
rs-
=
6 I
l Cash Response 050S Do 2 ltr Procedure would have been subject of internal review for TS R2_1 compliance - Perhaps this knowledge made me less questioning.
While I was aware that chemical cleaning was planned, I was not intimately involved in operation - (primarily concerned with DG keep warm tank problem).
na 3 ltr It has never been my practice to routinely enter TS action statements.
I would have sought some management review or guidance.
Did not properly understand the definition of loops not filled.
j gg_2 I was not involved in any of the other three chemical addition evolutions performed by dayshift on 10/12 & 13/88.
gg_1 As I understood definition of " loops not filled" on 10/11-12, during my shift TS 3.4.1.4.2 did not apply to my shift activities.
l i
Ag_1 I assume I was aware that the TS would apply if loops were not full.
l l
4 i
^
,-es
.d Utility Response Do2ltr/ The shift did not recognize that plant was in a " loops not filled" i
condition requiring valves to be closed and secured in position.
Operation possessed inadequate training and guidance.
pg_1 /
pursuant to the schedule, the RCS could not be opened until chemical cleaning was complete.
pg_R Mr. Hopkins recognized possibility that loops in a not filled condition and Mr. Gasser was apparently the only other licensed
. individual to do so.
]
pg_11 Cash & Bowles had insufficient training and guidance.
pa 15 pc.15 Citation for loops not filled in 1989 for similar event demonstrates' operator didn't understand " loops not filled." 2/89 og 17 Chem cleaning procedure only prepared and approved by HP/ Chem pq 35 Dept. and not reviewed by Ops or an other dept. Did not address RCS water level. Not reviewed by RC.
l 00 21 /
When faced with decision of whether chem addition evolution was permitted by TS, Mr. Kitchens had option to either proceed or cancel. Decision to proceed lengthened critical path schedule.
p3_3_4 No one in outage planning meeting recognized that TS involved with chemical addition operation.
2 N
i
i
~
i GPC 1.
The company's submittal in response to the Demand for Inforrnation goes tosomelengthindiscussinjentriesintoimmediateactionTS. What was the company s position at t1e time of the events under discussion about such entries? Were there any TS that could not be entered?
2.
What was the company's expectation of Mr. Kitchen when he found himself faced with a questionable TS and without an adequate procedure. Who should he have contacted, etc.?
If the didn't think he acted properly does that have anything to do with his reassignment?
(Assumin 3.
company'g Mr. Kitchens tells us R0s not involved.) Please explain the s expectations with respect to R0 involvement in the evolutions.
How do they explain the fact R0s were not involved?
4.
Are you aware of anyone from GPC who during the planning for the outage had concerns about adding chemicals in a loops not filled configuration?
5.
When that plan of action (adding in loops not filled) was discussed with other plants and Westinghouse, do you know if TS differences were a specific consideration in the discussionst e
I 1
i l
t REACTIVITY C0 r:ROL SYSTEMS POSITION INDICATION SYSTEMS - OPERATING LIMITING CONDITION FOR OPERATION 3.1.3.2 The Digital Rod Position Indication System and the Demand Position Indication System shall be OPERABLE and capable of determining the control and shutdown rod positions within i 12 steps.
APPLICABILITY:
MODES I and 2.
ACTION:
a.
With a maximum of one digital rod position indicator per bank inoperable either:
1.
Determine the position of the nonindicating rod (s) indirectly by the movable incore detectors at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and immediately after any motion of the nonindicating rod which exceeds 24 steps in one direction since the last determination of the rod's position, or 2.
Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
b.
With a maximum of one demand position indicator per bank inoperable either:
1.
Verify that all digital rod position indicators for the affected bank are OPERABLE and that the most withdrawn rod and the least withdrawn rod of the bank are within a maximum of 12 steps of each other at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, or 2
2.
Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
c.
The provisions of Specification 3.0.4 are not applicable when verifying system operability following repair.
SURVEILLANCE REQUIREMENTS 4.1.3.2 Each digital rod position indicator shall be determined to be OPERABLE by verifying that the Demand Position Indication System and the Digital Rod Position Indication System agree within 12 steps at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> f
except during time intervals when the rod position deviation monitor is inoperable, then compare the Demand Position Indication System and the Digital Rod Position Indication System at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
V0GTLE UNITS - 1 & 2 3/4 1-17
-. -.. -. -. -.~
t REACTIVITY CONTROL SYSTEMS POSITION INDICATION SYSTEM - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.1.3.3 One digital rod position indicator (excluding demand position indication) shall be OPERABLE and capable of determining the control rod position within 12 steps for each shutdown or control rod not fully inserted.
APPLICABILITY:
MODES 3* #, 4* #, and 5* #.
ACTION:
With less than the above required position indicator (s) OPERABLE, immediately open the Reactor Trip System breakers.
SURVEILLANCE REQUIREMENTS
(
4.l.3.3 Each of the above required digital rod position indicator (s) shall be determined to be OPERABLE by verifying that the digital rod position indicators agree with the demand position indicators within 12 steps when exercised over the full-range of rod travel, at least once per 18 months.
('
- With the Reactor Trip System breakers in the closed position.
- ee Special Test Exceptions Specification 3.10.5.
S V0GTLE UNITS - 1 & 2 3/4 1-18
i a
ACCESSION #: 8707250126 LICENSEE EVENT REPORT (LER)
FACILITY NAME:
Plant Vogtle - Unit 1 PAGE:
1 of 6 i
DOCKET NUMBER:
05000424 TITLE:
Manual Reactor Trips Due To Overly Conservative Annunciator Response Procedure EVENT DATE:
06/20/87 LER #:
87-038-00 REPORT DATE:
07/20/87 OPERATING MODE:
3 POWER LEVEL:
000 THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR SECTION 50.73(a)(2)(iv)
LICENSEE CONTACT FOR THIS LER:
NAME:
W. E. Burns, Nuclear Licensing Manager - Vogtle TELEPHONE #:
404-526-7014 COMPONENT FAILURE DESCRIPTION:
CAUSE:
X SYSTEM:
AA COMPONENT:
AIC MANUFACTURER:
W120 REPORTABLE TO NPRDS:
N SUPPLEMENTAL REPORT EXPECTED:
No ABSTRACT:
On June 20, 1987 and on June 25, 1987, the unit was in mode 3 end the shutdown rod banks were partially withdrawn when the reactor was canually tripped after receipt of an "RPI Urgent Alarm" annunciator on
. indicated failure of the Digital Rod Position Indicator (DRPI) for shutdown bank "B",
rod G-3.
After the initial trip, a thorough
'inopsetion of the DRPI system did not identify or locate a defective component.
After the second event, an inspection of the DRPI system was cgain performed which reproduced the failure mode.
The detector / encoder card for rod G-3 in the "B" DRPI data cabinet was discovered to have failed.
This card was replaced and subsequent testing demonstrated that proper indication had been restored for rod G-3.
Further review determined that annunciator response procedure 17010-1 was inconsistent with the safety significance of a failed DPRI indicator channel and Technical Specification 3.1.3.3.
Procedure 17010-1 has been revisod to require the operator, before opening the trip breakers, to immediately place the DRPI system in Data A only and Data B only to verify that the required' action of technical specifications 3.1.3.3 applies.
(End of Abstract)
TEXT:
PAGE:
2 of 6 A.
REQUIREMENT FOR REPORT This report'is submitted pursuant to 10CFRSO.73(a)(2)(iv) since the evsnts that occurred on June 20, 1987 and June 25, 1987 resulted in 1
.~
i i
manual'actuations of the. Reactor Protection System (RPS).
j B.
UNIT STATUS AT. TIME OF~ EVENT 1.
Power L'evel/ Mode' i
On June 20, 1987, at the time of the manual reactor trip at 0942 CDT,1 Unit 1 was in Mode 3 at 0% reactor power.
The reactor coolant system ~prer re and temperature were approximately 2225 psig and 548-degree, Fahrenheit, respectively.
l i
On June 25, 1987, at the time of the manual reactor trip at 3
0119 CDT, Unit 1 was again in Mode'3 at 0% reactor power.
The reactor coolant system pressure and temperature were approximately 2235 psig and 557 degrees Fahrenheit, respectively
'for this second event.
C, DESCRIPTION OF EVENT On June :20, 1987 at 0938 CDT, while in Mode 3 with a reactor startup in. progress, Shutdown Bank "A"
had been fully withdrawn and Shutdown Bank "B"
had been withdrawn to step 54 as indicated by the demand j
position' indicator.
At this time, a Rod Position Indication (RPI)
Urgent Alarm annunciator was received and the Urgent Alarm, General 3
Warning, and Rod at Bottom LED's on the DRPI display console illuminated s
for rod G-3, Shutdown Bank "B".
At 0942 CDT, the reactor trip breakers were opened in order to comply with the requirements of procedure 17010-1, " Annunciator Response Procedure for F 3-10 on Panel 1C1 on M.C.B.".
On opening the trip breakers, the operator observed that all rod bottom lights on the DRPI display illuminated, including the light for rod G-3.
.. TEXTS PAGE:
3 of 6 Following the trip, operators verified that no blown fuses were present in the rod = control cabinets and instrumentation and control (I&C) personnel investigated the cause for the annunciator and alarms which had been received.
To verify that proper voltage existed for the Control Rod Drive Mechanism (CRDM), I&C personnel and a site Westinghouse representative checked the output voltage of the CRDM power cabinets for the lift coil, movable gripper coil, and stationary gripper coil for rod G-3.-
Additionally, preliminary troubleshooting of the.DRPI system-included checking the "A"
"B" DRPI data cabinets for alarm indication on the cabinet LED display, verifying proper seating of cards in the data cabinets by visually inspecting card edge connectors, and verifying operability of the detector / encoder cards (slot A205) for rod'G-3 in data cabinets "A"
"B".
Preliminary troubleshooting identified no problems.
Subsequently, troubleshooting was performed in accordance with an action plan developed by I&C, operations, plant engineering support, and site Westinghouse representatives.
This troubleshooting included 2
~
1;..
I the following:
1 1.
A.DRP1 detector simulator was used to verify the operability of the G-3 rod position indication in accordance with instructions in the Westinghouse manual.
This verification was made for Data A and Data B and involved simulating rod movement through'all positions plus repeating the sequence around the 42 to 60 step area where-the problem had occurred.
2.
Operability of the DRPI coil stacks for rod position indicator 2
G-3 was verified in accordance with instructions of the Westinghouse manual.
Resistance readings were taken to verify
.l continuity for the DRPI coil stacks and cables.
)
3.
Operability of.CRDM G-3 was verified by taking' resistance readings i
for the CRDM lift coil, movable gripper coil, and stationary.
gripper coil.
4.
Operability of the DRPI system for rod G-3 was verified by performing surveillance procedure 14750-1 " Digital Rod Position Indication 18 Month Operability Test".
This consisted of withdrawing and inserting rod G-3 with the DRPI display console in Data A only, Data B only, and in Data A&B.
TEXT PAGE:
4 of 6 During the subsequent troubleshooting, the DRPI system functioned properly.
Therefore, the DRPI system was declared operable at 0210 CDT on June 21, 1987 and the reactor was restarted.
On June 25, 1987 at 0118 CDT, while again in Mode 3 with a reactor startup'in progress, Shutdown Bank "A"
had been fully withdrawn and Shutdown Bank "B"
had been withdrawn to step S2 as~ indicated by the demand position indicator.
At this time, another DRPI failure occurred for shutdown rod G-3 (i.e. an RPI Urgent Alarm annunciator was received and the Urgent Alarm, General Warning, and Rod at Bottom LED's lighted on the DRPI display console for rod G-3).
On receipt of the failure indication, the operator used the rod control in-hold-out switch to return Shutdown Bank "B"
to step S1.
This action cleared the indicated DRPI. failure alarms and gave a DRPI display position indication for rod G-3 of step 42.
Although, position indication appeared to be restored to within the limit of Technical Specification 3.1.3.3, the operator again opened the reactor trip breakers at 0119 CDT in order to comply with the requirements of procedure 17010-1.
On opening the trip breakers, the operator observed that all rods dropped in as indicated on-the DRPI display and that all rod bottom lights illuminated.
Based on the report of the operator that inserting Shutdown Bank "B"
to step Si had cleared the alarms, it was believed that at 1 cast one DRPI data channel was operrble.
Since positions 42 and 54 are data "A"
positions, data cabinet "B"
was suspected.
Troubleshooting was therefore performed as follows for rod G-3 using surveillance procedure 14750-1:
3
i I
1.
With the DRPI display console in Data "A"
"B",
rod G-3 was withdrawn to stop 52 where the indicated DRPI failure i
reactuated.
2.
The DRPI display console was switched to Data "A"
only and indication was regained for rod G-3 with position 54 indicated.
3.
The DRPI display-console was switched to Data "B"
only and the alarms actuated again.
4.
The DRPI display console was switched back to Data "A"
"B" and the DRPI failure indication remained.
TEXTS PAGE:
5 of 6 The results of this troubleshooting satisfactorily demonstrated that data "B" cabinet was providing erroneous information while the data "A"
cabinet was fully operational.
Therefore, troubleshooting of the data "B" cabinet was performed and the detector / encoder card
-(Model No. 1468F53G01) for rod G-3 was found failed.
The failed detector / encoder card was replaced and a functional test using,the DRPI simulator was performed.
Also, surveillance procedure 14750-1 was performed again for rod G-3.
All results were satisfactory
)
and a successful reactor startup was completed on June 25, 1987.
D.
CAUSE OF EVENT The cause for receipt of the RPI urgent Alarm annunciator during both j
events, was eventually determined to be the failed detector / encoder card for rod G-3 in data cabinet "B".
This card was apparently
)
failing to encode and transmit the rod position information to the DRPI Display Module for the 49 to 54 step range.
The root cause for the manual reactor trips on June 20, 1987 and June 25, 1987 was an overly conservative requirement in annunciator response J
procedure 17010-1.
This procedure required the reactor trip breakers to be opened immediately on receipt of an RPI urgent Alarm annunciator; this requirement applied only if in Modes 3, 4,
or 5 and with all rods not fully inserted.
T.is requirement was placed into 17010-1 since this annunciator alarm was considered an indication of not meeting the limiting condition for operation (LCO) of Technical Specification 3.1.3.3; that is, not having a DRPI operable and capable of determining the control rod position to within plus or minus 12 steps for each shutdown or control rod not fully inserted.
The investigation that was performed following the manual trip.on June 25, 1987, demonstrated
'that the Data A cabinet was fully operational.
Therefore, the DRPI system with the display console switched to Data "A"
only, would have still met the LCO of Technical Specification 3.1.3.3 during these events.
TEXT PAGE:
6 of 6 4
1
_ _ _. _. _. _ _ _ _ _. ~ _ _. _ _ _. _.. --
i
- 9 i
l E.
ANALYSIS OF EVENT.
The' failure of the. detector / encoder card-in.the "B"
DRPI data. cabinet L
resulted.in lost position indication for Shutdown Bank "B",
rod i
G-3.
This indication could have been restored.had-the DRPI display console.been switched to Data "A"
only.
The' failure of the card did not impact the actual operability of rod G-3 or the ability to i
~
~
. properly trip this rod.
Therefore, it is concluded'that neither the safety of the plant nor'the health and safety of the.public were affected.
F.
CORRECTIVE ACTIONS-.
4 faile' detector / encoder card was replaced on June 25, 1987.
The 5
The d
failed card will be returned to Westinghouse for repair.
j Procedure 17010-1 has been revised to require the operator, before
'I opening'the trip breakers, to immediately place the DRPI System in Data A only and Data B only.
This allows for a prompt determination-of whether.one DRPI channel is.still capable of determining rod position, and therefore, whether the LCO for Technical Specification 3.1.3.3 is.still being met.
i fi.
ADDITIONAL INFORMATION 1.
' Failed Component Identification
-i DRPI Data Cabinet Detector / Encoder Card Westinghouse Model No. 1468F53G01 2.
Previous Similar Events i
l' None I
I 3.
Energy Industry Identification System Code Control Rod Drive System - AA ATTACHMENT # 1 TO ANO # 8707250126 PAGE:
1 of 2 i
Georgia Power Company
[
333 Piedmont Avenue l
Atlanta, Georgia 30308 Telephone 404 526-6526 l
Mailing Address
. Post Office Box 4545 Atlanta,-Georgia 30302-Georgia Power L.
T.
Gucwa the southern electric system j
Manager Nuclear Safety l
and Licensing 5
1 I
e SL-2903 0412m l
]
July 20, 1987^
l U.
S.
Nuclear Regulatory Commission
! ATTN Document Control Desk
)
Washington,-D.
C.
20555 l
)
PLANT VOGTLE - UNIT 1 l
I NRC DOCKET 50-424 i
OPERATING LICENSE NPF-68 I
LICENSEE EVENT REPORT MANUAL REACTOR TRIPS'DUE TO OVERLY-CONSERVATIVE ANNUNCIATOR RESPONSE PROCEDURE l Gentisment l
' Pursuant to the requirements of 10 CFR-50.73(a)(2)(iv), Georgia Power l Company is' submitting a Licensee Event Report (LER) concerning events where manual reactor trips resulted from an overly conservative annunciator
! response procedure.
Sincerely,
/s/ LT Gucwa L.
T.
Gucwa
PAH/Im
Enclosure:
LER 50-424/1987-038 c
(see next page)
ATTACHMENT # 1 TO ANO # 8707250126 PAGE:
2 of 2 Georgia Power U.
S.-Nuclear Regulatory Commission July 20, 1987
".Page;Two ci-Gnorgia Power Company Mr.
R.-E.
Conway l
l Mr. J.
P. O'Reilly L
Mr.
G.
Bockhold, Jr.
Mr.
J.
F.
D'Amico l
Mr.
C.
W.
Hayes GO-NORMS i
Southern Company Services Mr.
R.-A.
Thomas Mr.
J.
A.
Bailey 6
l 1
l i
. _.. _... _. -... _ _ _. _. _. _. _... _. _. _ _ _.. - _ ~. _. _. ~. _.. _. ~.. _ _.
i-I' t
I i
Shaw, Pittman,,Potts & Trowbridge-Mr.
B.
W.
Churchil1~, Attorney-at-Law i
- T r o u t m a n,.l S a n d e r s, Lockerman & Ashmore Mr.
A.
H..Domby, Attorney-at-Law U.
S. Nuclear. Regulatory Commission f
Dr.
J.'N.
Grace, Regional Administrator Ms.
M.
A.= Miller, Licensing Project Manager, NRR (2 copies) l l
-Mr.
J.
F.
Rogge, Senior Resident Inspector-Operations, Vogtle
)
'Gnorgians Against Nuclear' Energy l
.Mr.
D. Feig j
Ms-
'C.
Stangler l
'0412m
- END OF-DOCUMENT ***
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' ##'pa nee t*1TED STATES
/
NUC. \\R RE*ULATORY COMMISSION
/
1 c E *lON il
,g
]
101 MA~lETTA STIEET,NO.
'y ATLANTA, GEORGIA 30323 i!* \\
)r SEP 17 IS91 Docket Nos. 50-424, 50-425 License Nos. NPF-68, NPF-81 i
Georgia Power Company ATTN: Mr. W. G. Hairston, III i
Senior Vice President -
Nuclear Operations P.'O. Box 1295 i
Birmingham, AL 35201 Gentlemen:
CONFIRMATION OF ME' TING - ENFORCEMENT CONFERENCE - V0GTLE
SUBJECT:
E UNITS 1 AND 2 This confirms our telephone conversation of September 16, 1991, concerning an Enforcement Conference to be conducted at the NRC Region II Office at 12:00 p.m., on September 19, 1991.
This meeting was requested in order to discuss an event which occurred at Georgia Power Company's Vogtle Generating Plant on October 12 and 13, 1988.
Should you have any questions regarding these arrangements, we will be pleased to discuss them.
Sincerely,
./44' 1
Stewart D. Ebneter Regional Administrator
Enclosure:
Proposed Meeting Agenda 4/
i
/
[,-
utomoux
8 i
i ENCLOSURE PROPOSED AGENDA FOR V0GTLE ENFORCEMENT CONFERENCE i
GEORGIA POWER COMPANY (GPC) i
'I. Opening Remarks NRC II. Enforcement Overview NRC 1
1 III. Remarks by GPC (30 minutes)
GPC IV. Staff Discussion NRC V. Closing Summary GPC i
VI. Closing Remarks NRC 1
4 o
1
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i