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7 UNITED STATES 3
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MEMDRANpVlf..TO:
OStewart D. Ebneter, Regional Administrator HEAi.
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William T. Russell, Director Office of Nuclear Reactor Regulation Jack R. Goldberg, Deputy Assistant General Counsel for Enforcement Office offhe. Ale ral Counsel FROM:
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SUBJECT:
01 REPORT 2-95-008; RE: ST. LUCIE NUCLEAR PLANT: ALLEGED i
DISCRIMINATION AGAINST AN INSTRUMENTATION AND CONTROL TECHNICIAN FOR REPORTING SAFETY CONCERNS The above captioned 01 report involves an allegation of discrimination by an instrumentation and safety technician at Florida Power and Light Company's St.
Lucie Nuclear Plant that he was discriminated against for engaging in protected activities. 01 did not substantiate the allegation. Therefore, it appears that enforcement action is not appropriate in this case.
I do not intend to request an OGC analysis of this report. We will consider the matter closed unless we receive a different view within three weeks of the date of this memorandum.
Please contact Michael Stein of my staff with any 4
comments.
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J. Milhoan, DEDR
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R. Zimmerman, NRR G. Caputo, 0!
F. Hebdon, NRR/PD L. Weins, NRR/PM B. Uryc, RII i
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RerWe Power & Ught Company. P.O. Sea 128, Fort Merce, n 3eE4-etD my.
3 September 11,1996 5:pL.
L-96-227 10 CFR 73.71 U. S. Nuclear Regulatory Commission i
Attn:
Document Control Desk Washington, D. C. 20555 Re St. Lucia Units 1 and 2 Docket Nos. 50-335 and 50-389 Reportable Event:
96-S01 Date of Event: August 14, 1996 1
Tannarina with Kay switrhan on the Hot shutdown cantrol Panals The attached Licensea Event Report is being submitted pursuant to the requirements of 10 CFR 73.71 to provide notification of the subject event.-
Very truly yours,
. A. Stall Vice President
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St. Lucie Plant JAS/REN Attachment ccaStewartD.Ebneter,RegionalAdministr[ tor,USNRCRegionII Senior Resident Inspector, USNRC, St. Lucia Plant S l 5 ~ D y' R - $ 6 l f nu m
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l ST. LUCIE SPECIAL INSPECTION TEAM t
Team Charter A.
Develop a chror ological sequence of events describing identification of and l
Econese responses to suspected precursor and known tampering events.
l IMunday-lead) l j
B.
Evaluate hcensee's response to the recent suspected and known tampenne events l
to determine if:
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- plant components, which have had tempenng, have been adequately j
evaluated and the known degradation has been corrected. (Munday) i
- plant safety systems have been sufficiently evaluated for potential tempenne to assure they can perform their intended functions.
(Munday-lead: Weems)
- plant managemant adequately responded to the suspected precursor and known tempenne events. (Barr)
\\ - plant management has implemented adequate interim to detect new ta,npering. (wiens-ioad: Thompson-S.c.gv 9
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- plant investigations are sufficiently thorough in attempting to identify the person (s) responsible for the tempering. (Thompson) j
- plant systems / components that experienced tampanng have been maintamed consistent with the plant licensing basis including location and
- personnel access.to equipment. (Wiens)e--
- assess whether personnel access to tampered components was in accordance with approved security plan and other regulatory requirenwnts.'
(Thompson)
C.
Issue an unclassified, final report by September 11,1996. A supplemental report which includes safeguards information may also be issued at the same time.
D.
Inspection team will report to the Director, Division of Reactor Safety, Region 11.
Inspection Team Members K. P. Barr - Team Leader L. A. Wiens J. T. Munday D. H. Thompson 8/16/96 U
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k September 19, 1996 i
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Flonda Power and Light Company l
ATTN: Mr. T. F. Plunkett President - Nucisar Division i
P. O. Box 14000
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Juno Bearli, FL 33406 0420
SUBJECT:
NRC SPECfA.L INSPECTION REPORT 50-335/96-16 AND 50-389/96-16 AND j
iCTiCE OF VIOLATION i
Dear Mr. Plunkett-l On August 23,1996, the NRC completed a speaal inspechon involving component tamponng events at your St. Lucie reactor facelsbes. The enclosed report presents the results of that 3
inspecten.
i Overall, St. Lucie's response to the potental and actual tampenng events between May and
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August 1996 was
^'iMe y. Some response deScencsos were identiGod and are semah j
in the details of the report. Also, based on the results of this inspection, cortam of your i
actubos appeared to be in vioisten of NRC requirements, as specined in the encioned l
Nobce of Violaten (Nobce).
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In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosures will be placed in the NRC Public Document Room (PDR).
Sincerely, i
(Original signed by A. F. Gibson) 1 Albert F. Gibson, Director Division of Reactor Safety Docket Nos.: 50-335, 50-389 License Nos: DPR-67, NPF-19
Enclosures:
- 1. Notice of Volation
- 2. Inspechon Report 50-335/96-16 and 50-389/96-16 9 &0%2700Mo oc w/encis: (See page 2)
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4 J. A. StaN Jack Shreve, Public Counsel Site Vice Presulent Offlos of the Public Counsel So Lucie Nuclear Plant clo The Florida Legislature 1
P. O. Box 128 111 West Madmon Avenue, Room 812 Ft. Piena, FL 34954 4128 Tallahassee, FL 32399-1400 3
Y H.- N. Paduano, Manager Joe Myers, Director Lkanseg and Special Programs Division of Emergency Properedness Ronda Po*ar and Light Company Department of Community Affairs 1
i P. O. Box 14000 2740 Centerwow Drive
]
Juno Beach, FL 3340lH)420 Tallahassee, FL 32399-2100 J. Scarola Thomas R. L. Kindred 4
Plant General Manager County Adminstrator St. Lucie Nuclear Plant St. Lucie County j
P. O. Box 128 2300 Virginia Avenue i
Ft. Pierce, FL 34954-0128 Ft. Pierce, FL 34982 1
E. J. Wonkam Charles B. Brinkman Plant Licenseg Manager Washmgton Nuclear Operatens l
St. Lucie Nuclear Plant ABB Combustion Engmeenng, Inc.
P. O. Box 128 12300 Twmbrook Parkway, Suite 3300 i
Ft. Pierce, FL 34954-0218 Rocimile, MD 20852 i
J. R. Newman, Esq.
Distnbuten w/enci-Morgan, Lewis & Bocious K. Landis, Ril l
1800 M Street, NW
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~3. Norrts, NRR Washington, D. C. 20036 B. R. Crowley, Ril G. A. Hallstrom, Ril John T. Butler, Esq.
PUBLIC l
Steel. Hector and Davis 4000 Southeast Financial Center NRC Resident inspector 4
Miami, FL 33131-2398 U.S. Nuclear Regulatory Comm.
7585 South Highway A1A Bill Passetti Jensen Beach, FL 34957-2010 Office of Radiation Control i
Department of Health and i
Rehabilitative Serwces s
1317 Winewood Boulevard Tallahassee, FL 32399-0700 om.,
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i Flonda Power and Light Company Docket Nos. 50-335, 50-389, i
St. Lucie Nuclear Plant License Nos. DPR 67, NPF-19, i
j During an NRC inspection conducted on August 19-23,1996, wolabons of NRC requerements were identified.. In accordance with the " General Statement of Policy and Procedure for NRC
. Enforcement Achons," NUREG-1600, the wolations are hated below-A.
10 CFR 73.71, Reportmg of Safeguards Events, Appendix G, (a)(3) Reportable i
Safeguards Events, requires the licenses to report to the NRC within one hour of discovery, followed by a wntten report within 30 days, events which cause interruption l
of normal operations through tampenng with controls including the security system.
)
The boonsee's Secunty Procedure, SP4006125, Reportmg of Safeguards Events, i
Rension 9, dated April 20,1995, Paragraph 8.2 (1) defines one of those speafic events as being a."confinned tempering of suspicious origin with safety or security equipment."
Contrary to the above on July 29,1996, the licensee failed to follow their procedure j
and report the confirmed tampenng with security equipment (locks) within one hour to j
the NRC.
l This is a Severity Level IV violation (Supplement lii) w i
B.
. Technical Speedicebon 6.8.1.a requires that wntten procedures be established, implemented, and maintained covenng the achvities recommended in Appendix A of j
Regulatory Guide 1.33 Revision 2 February 1978. Appendix A, paragraph 1.c includes administrative procedures for equipment control. Administrative Procedure i
No. 2 0010123, "Admmistrative Control Of Valves, Locks And Switches," Rewsion 73 l
implements this requirement with respect to administratively controlled keys.
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j Step 8.2.1 of this procedure states in part that cubicles containing cntical controls in i
remote locahons shall be locked and the keys maintained under Administrative l
Control.
j Contrary to the above, on August 19,1996, keys used for the ce g ggpp 4
Operated Relief Valves V1474 and V1475 located in the 2A and l
penetration rooms respectively, were located in the unlocked cu switches.
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This is a Severity Level IV violation (Supplement 1).
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j Pursuant to the provisions of 10 CFR 2.201, Florida Power and Light is submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
.1 Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, Region 11, and a copy to the NRC Resident inspector at the facility that is the subject of this j
potice within 30 days of the date of the letter transmitting this Notice of Violation (Notice).
j This reply should be clearly marked as a " Reply to a Notice of Violation" and should include
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, for each violation: (1) the reason for the violabon, or, if contested, the basis for dispuhng the violation, (2) the conochve steps that have been taken and the results achieved, (3) the i
corrective steps that wlN be taken to avoid further violations, and (4) the date when fun l
compliance wlN be achieved. Your response may reference or include previous docketed conospondence if the conospondence adequately addresses the required response. If an adequate reply is not receeved within the time specNied in this Notice, an order or Demand for l
Information may be issued as to why the license should not be modified, suspended, or i
revoked,- or why such other action as may be proper should not be taken. Where good-cause is shown, considersbon will be given to extendmg the response time.
j Because your response will be placed in the NRC Public Document Room (PDR), to the extent possible, it could not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without redaction. If personal privacy or J
propnetary informahon is necessary to provide an acceptable response, then please provide a bracketed copy of your response that identifies the information that should be protected i
and a. redacted copy of your response that deletes such information. If you request withholding of such material, you HBig specNiceNy identify the portions of your response that you seek to have withheld and provide in detail the bases for your claim of withholdmg (e.g.,
explain why the disclosure of information will create an unwarranted invasion of personal j
pnvecy or provide the informabon required by 10 CFR 2.790(b) to support a request for with-holding confidential commercsal or financial informabon). If safeguards informabon is i
necessary to provide an acceptable response, please provide the level of protechon j
described in 10 CFR 73.21.
j Security or Safeguards information should be submitted as an enclosure to facilitate withholding it from public disclosure as required by 10 CFR 2.790(d) or 10 CFR 73.21.
Dated at Atlanta, Georgia this(PNay ofcM996 s
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U.S. NUCLEAR REGULATORY COMMISSION l
4 REGION 11 i
Docket Nos: 50-335, 5 4 389 3
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Report No:
50-335/96-16, 50-389/96-16 l
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Licensee:
Florida Power & Light Co.
3 Facilty:
St. Lucie Nuclear Plant, Uruts 1 & 2 i
Location:
9250 West Flagler Street Miami, FL 33102 4
Date:
August 23,1996 Inspectors. K. Barr,.Toam Leader..
J. Munday, Resident inspector L. Wiens, Project Manager D. Thompson, Secunty inspector i
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Appre:d by: A. F. Gibson, Director
' Division of Reactor Safety
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l TABLE OF CONTENTS i
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l EXECUTIVE
SUMMARY
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REPORT DETAILS 5
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.' 02.1 May-June 1996 Relief Valve Potential. Tampering Events 5
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02.1.1 Evaluation and Cor.ective of Damaged Components 6
02.1.2 Evaluaten of Plant System for Addihonal Tampering 7
02.1.3 Site Managements Response to the May 1996 Event 8
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02.2 Summer ( of the July 1996 Lock Tampering Event 10 i
02.2.1 Evaluation and Conection of Damaged Components 11 j
02.2.2 Evaluaten of Plant System for Additional Tampenng 11 02.2.3 Site Management's Response to July 26,1996 Tampering Event 12 l
02.2.4 Implementaten of intenm Acton to Detect New Tampering 13 1
S1.2.5 Secunty inveshgation of the Event 13 l
S1.2.7 Evaluaten of cot-fr.cs with the Physical Security Plant 14 i
02.3 Summary of August 1996 Event Concoming Damage to Hot Shutdown Panel Keylock Switches 14 j
02.3.1 Evaluation and Conecten of Damaged Components 15 j
02.3:2 Evaluation of Plant System for Additenal Tampering 15 1
02.3.3 Site Management's Response to the August 14 Tamper Event 19 l
02.3.4 Implementatpon of Intenm Actens to.. Detect,New Tampering
, 21 S1.3.5 Security irr;nO=E-i of Event 22 j
02.3.6 Plant Licensing Basis 23
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S1.3.7 Evaluation of Comphance with Physical Security Plant 24 INSPECTION PROCEDURES USED 26 i
ITEMS OPENED, CLOSED., AND DISCUSSED 26 EXIT MEETING
SUMMARY
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PARTIAL LIST OF PERSONS CONTACTED 28 l;
LIST OF ACRONYMS USED 29 t
j Attachment A: Chronological Sequence of Events A-1
- . Attachment B
- Infonnaten Provided to Licensee By NRC On j
August 15,1996 B-1 1, Attachment C: Photographs Showng Valve Locations and i
i Examples Of Damaged Locks and Key Lock Switches C-1 I, Attachment D: List of Licensee Documents Reviewed D-1 l
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I EXECUTIVE
SUMMARY
l St. Lucie Nuclear Plant, Units 1 & 2
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NRC inspedion Report 50-335/96-16, 50 389/96-16' A Chronologscal Sequence of Events was established by the ina pedion team. That listing is i
contained in Enclosure 2, Attachment A to this report.
i Overall, the hoenese's response to the potential and actual tampering events between May i
and August 1996 was satafactory. Some response deficsoncies were identdied and are ~
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discussed in the details of the report in addition, two violations of regulatory requirements j
were identified for (1) failure to make a report to NRC under 10 CFR 73 concoming damaged
- locks and (2) failure to follow procedure concoming control of keys to cnbcal controls. An unresolved item (URf) was identdied concommg differences between the Updated Fmal Safety Analysis Report (UFSAR) desenphon of the Hot Shutdown Panel (HSDP) for Unit 1 and the instrumentation actually installed. An inspector follow item (IFI) was identified for follow up on final implementation of intenm achons to detect new tampering in a more timely manner.
in May and June 1996, the licensee identified two pressure relief valves which, when tested, were found to have pressure setponts 55 percent and 9 percent above their design values.
These valves were also found to have broken wire seals. The licensee's documented technical evaluabon identdied, as possible root causes, tampenng or unauthorized work by plant personnel. Licensee management subsequently determined the valve anomalies were not due to tampering.
Through discusstoris with the licensee..and documentatiortfovow, the inspectors conclugled that the licensee's polecy on the use of wire seals was inconsistent. There were no clear instructions to apply wire seals and, as a result, a number of valves did not have seals attached.
Based on independant review of the documented facts, observations of the installed valve configurations, and the effort required to access the valve spnng tensson mechanisms, the inspectors concluded that tampenng, although it could not be conclusively ruled out, was not iikely to have occuned in either of these specific cases. A person knowledgeable. enough about relief valve operation to tamper with the valves could use ara easier method to prevent proper operation of the valve. The more likely cause for the misadjusted valve was poor maintenance practices.
The inspectors verified through documentation review that the two valves were either replaced or repaired.
"w inspectors verified through documentation review, that the V2325 setpoint was adjusted, property tested and the valve reinstalled in the system.
The inspectors concluded that site management appropriately pursued identification of the cause for relief valve V3483 having a high setpoint. In addition, because of the broken wire valve seal, apprep/i walkdowns were conducted to determine the extent of possible valve
. tampering. Once the extent was established, management appropriately evaluated and
'dispositioned the deficsonc'es.
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Since tampering with valves V2325 and V3483 could not be cere?d; ruled out,.
management's decssion to alert Secunty of the tampering possibility was =--;-T+itt.
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However, due to a communicatens lapse, she Secunty was not notiRed. The inspectors also j
concluded that failure to follow through on alerting Site Security produded actions to enhance security force awareness to other possible tampenng events.
l The inspectors determned that the event would not have been required to be reported to the p-NRC. However, the Security Manager should have been informed of the event because i
Security Procedure, Reportmg of Safeguards Events, SP-0006125, Paragraph 5.2 states that "the plant security supervisor is responsible for making report ability determination under 10 i
CFR Part 73.71."
i On July 26,1996, eleven examples of actual padlock and door lock tampering were identified. Nine padlocks and two door locks were found to have been intentionally damaged by having foreign material injected into the lock cores. These locks controlled personnel access to vanous pieces of plant eqt.ipment.
The damaged locks were repaired and verified operational.
Although the boensee's response to the damaged locks was completed in a timely manner, the extent of condition evaluebon did not identify keylock switches as other locking devices that needed to be checked for damage.
Management's response to the July event was not thorough in that keylock switches were not checked for damage until August.
Identification of tampering of components within the vital area of the plant demonstrated that additional tampenng could hkely occur. Therefore, the licensee should have considered addibonal measures to detect new tampering of equipment at the site in addition to alertmg the Security force.
The Corporate investigative staff adequately reviewed the event.
The licensee failed to follow their procedure and report the confirmed tampering with the security equipment (locks) to NRC within one hour. This is a violation of regulatory requirements.
On August 14,1996, three additional examples of actual lock tampering were identified. The lock mechanisms of the two keylock switches on the Unit 2 HSDP and the keylock switch on the Unit 1 HSDP were found to be intentionally damaged by having foreign material injected into the lock cores. These were the only keylock switches on the panels.
The inoperable Unit 1 power operated relief valve (PORV) control switch and the Unit 2 "A" and "B" channel safety injechon actuation system (SIAS) bypass switches were replaced and operability was adequately verified.
Following extensive reviews done by the licensee and independent verifications by NRC, the inspectors concluded there was no evidence of additional tampering.
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The inspectors identified that keys to operations equipment were not property maintained in i
accordance with gh requirements. This represents a violation for' failure to fotow j
procedural requirements.
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Site management satisfactority evaluated, consistent with the known examples of tampenng, the operational capability of the plant safety systems to perform their intended safety funchons
' Site management satisfactorily evaluated plant areas for foreign material and abnormalities.
l Site management did not use all available plant documentation of equipment deficiences j
(e.g., plant work orders) in its search for addshonal examples of tampeting.
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Site management should have been more proactive in establishing interim actions to detect new tampering in a more tunely manner by usmg plant staff observers as well as Secunty 1
force members. The interim actions M::E=ey identafled by plant management, if property l
- implemented, should provide reasonable assurance that new tampenng were be promptly
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detected.
1 The security force implemented good preventative measures to detect or prevent new tampenng with plant equipment.
I The licensee took appropnate and extensive actions to determine the individual (s) involved in the lock tampenng event (s).
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4 With one exception, the design and insta#ation of the HSDPs for St. Lucie Units 1 and 2 were in accordance with the licensing basis of the plants. The FSAR d::3-4-3 of the controls and instruments installed on the HSDP for St. Lucie Unit i did not match the installed j
equipment in that the FSAR d:::@m did not indicate the installed nucisar instruments.
j The failure of the FSAR to correctly describe the installed equipment is identified as an URI.
Control of access to the HSDP rooms of St. Lucie Unit 1 and 2 was in accordance with the approved PSP for the site.
The licensee was in compliance with the site PSP regarding access controls, patrols, alarm station operations, fitness for duty and access authorization.
During this site inspection, the inspectors independently reviewed a large number of plant records of Condition Reports (CRs) and Nuclear Plant Work Orders (NPWOs) in an attempt to identify any previously unidentified tampering events. No new tampering events were identified by the team. Attachment B contains information provided to St. Lucie site management by NRC to assist in the site's response to the events. The attachment contains NRC Information Notice 83-27 concoming deliberate acts directed against plant equipment and intemal NRC guidance for plant system checkout follow:ng suspected sabotage.
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Enclost' e 2, Attachment C contains illustrative photographs of the valves, padlocks and keylock switches that were the subject of this inspechon O
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e Rooort Details a
l Summary of Potential and Ach=8 Plant Tamoenna Events l
l In May'and June 1996, the licensee identdied two pressure raisef valves which, when tested, i
were found to have pressure setpoints 55 percent and 9 percent above their design values.
.The licensee's technical evaluation identified, as possible root causes, tempering or i..
unauthonzed' work by plant personnel.
i On July 26,1996, eleven examples of actual padlock and door lock tampering were i
identdied. Nine padlocks and two door locks were found to be intenbonally damaged by l
having foreign material injected into the lock cores. These locks controlled personnel access i
to various pieces of plant equipment.
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On August 14,1996, three examples of addihonallock tampenng were identdied. The lock l
mechanisms on the two key lock switches on the Unit'2 HSDP and the key lock switch on the i
Unit 1 HSDP were found to be intenbonally damaged by having foreign material injected into i
the lock cores. These were the only key lock switches on the panels.
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O2 Ops"d Status of Facilities and Equipment l
S1 Conduct of Security and Safeguards Activities j
O2.1 May-June 1996 Relief Valve Potential Tamperina Events
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On May 13,199Crohef va'Ive V3483 Was"removedMtfs plant for a planned check olits l
pressure relief setpoint. This valve had been installed on the 1A Low Pressure Safety injechon (LPSI) pump retum line. On May.15,1996, the planned check of the valve setpoint was initiated. Teshng determined the pressure setting to be approxsnately 55 percent above i
it's design set point. This valve was found with its wire seal broken and wrapped around the j
valve cap. A broken wire seal could be an indicator that the valve intemals experienced j
.some tampenng. As recorded in the licensee's CR documentation, the root cause of this
- 1 failure was stated by the bcensee to be "apparently due to tampering or mesadjustment of the j
valve's set screw controlling spring tension by unauthorized individual (s)." Figures 1 - 3 show j
the installed configuration for valve V3483.
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j Discovery that valve V3483 had an out of tolerance setpoint coupled with a broken wire seal
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resulted in the licensee visually inspecting 150 additional safety relief valves to determine if other valves had broken wire seals. No Unit 2 valves had broken or missing seals.
However, ten Unit i valves were identdied to have broken or missing wire seals. About June 17,1996, pressure rehef valve V2325, which was one of the ten identified with a broken or missing seal, was pressure tested aM found to be within its pressure setpoint acceptance criteria but about 9 percent above its intended setpoint. Valve V2325 had been installed on the 1B Charging Pump discharge line. The licensee evaluated the setpoint difference and identified, as a potential cause, " unauthorized setpoint adjustment by personnel outside the scope of work controls." Figures 4 and 5 show the installed configuration for valve V2325.
None of the romaning nine Unit i relief valves with broken or missing seals were assessed by the hcensee as boeng out of calibration.
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s 02.1.1 Evaluation and Corrachon of Demaned Components I
a.
Inacection Scope i
Review liconese's evalumbon of the damaged components to denomune If the es.4ound condinons represented potenbal tempenne and detemune if the damaged components were replaced or the damese coneded.
b.
06eervations and Firulinos i
The inspectors reviewed CR g6 08g0, wtuch documented that the as-found lift setpoet j
of the 1A LPSI pump discharge rehof valve V3483, wt s approxunstely 55 percent i
above its set pressure. This report stated that, after tta valve was removed from the j
system it was placed in the drummmg room to be tested. Prior to teshng, an insbal inspecten identified that the adpustment cap saww seals were brott n and the nozzle i
forgeg was not property seated in the valve' body and was loose. In the past it had i
been a common maintenance predice to instat wire seals as a method to quiddy and j
casily identify if tempering had occ med. However, the lack of a seal did not provide conclusive evidence that tampenng had occurmd. Seal wires could be broken during i
installabon, maintenance of pipe insulation or other mairdenance activities occurring in l
the same area. M::;-M testmg was performed with the valve in this condibon
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_ and the aforementioned resuRs were obtsmed.
Through descussion with the boonsee and documentation reviews., the inspector determmed that, once the valve was installed, tamponng ac$stments to the V3483 setpont Hiquired ttie ' removal 6f four 2.5" X~0.5" cap bolhs tightened to a torqusI"value of 45 Ft-lbs. in order to gain access to the adjushng nut. The cap bolts were not reported as havmg been found loose when the valve was removed from the system The inspector observed the valve installed in the system and noted that it was located approximately twenty-five feet above the floor, making it accessible only with the use of a long ladder, scaffoldmg or crewing along the===aaM pipe. Figures 1 - 3 show the location of the valve.. Although the. report conduded that the root cause of the fadure was apparently due to tampenng or nusedjustment of the valve's set screw ce,a,J.;,,g the spnng tension, site management assessad the events to most hkely be due to poor work pracbees. Documentabon review irwincated the valve was subsequently replaced with a protested spare.
The inspectors venlied that a Plant Manager's Adion item, PMg6-06-483, was in;tiated to revise site procedures M-0810, Bench Testag of Safety Rehof Valves, and M-0705, Main Steam Safety Valve Maintenance and Set Pressure Toshng to indude the installabon of seals on rehof valves following maintenance.
c.
Conclusions 1
Through discussions with the licensee and documentaten revow, the inspectors concluded that the bconsee's policy on the use of lead seals was inconsstent. There were no clear licensee instructions to apply the seals and as a result a number of i
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instated vahms did not have seals attached. The beenese planned to address this
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issue through a revisoon of site procedures which will formahze and require the use of i
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the seals.
l Based on independent rewsw of documentabon, observatens of the instaged va6ve 1
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configurations, and the effort requwed to access the valve spnng tensen mechamems, i
the inspectors concluded that tampenng, although it could not be condusively naled out, was not moly to have occurred in this speedic case. The more moly cause for-this misadjusted valve was poor maintenance practices.
1 The inspectors venfied through documentabon review that the two valves were either replaced or repasred O2.1.2 Evaluation of Plant Systems for Additional Tamperina a.
Inspechon Scope Verify plant safety systems have been sufficiently evaluated for potential tampesing to assure they can perform their intended funchons.
b.
Observabons and Findmos in response to the high as-found pressure setpoint of the V3483 and the broken wire seal on the valve, the licensee performed an inspechon of wire seals on an additional 150 safety related valves. This effort was documented in CR 96-1247. After a review of both utilts, a total of 10 Unit ~1 #1ves worsideiiilEed with damaged or miss$
seals. Three of these valves had the sealintact but damaged. Frve of the valves had proper lift setbng visually venfied by the possbon of the adjustment bolt. One of the valves had proper lift setting venfled by bench test. One of the valves,1B charging pump discharge rehof valve, V2325, was tested and found to have its lift nothng approxwnstely 9 percent high. The keensee initiated CR 96-1469 to idenbfy the root cause of the high setpont on this valve. The valve was eA::g=.y disassembled in accordance with Work Order 96015293 and no abnormahties were identdied.
Followng adjustment of the setpont, the valve was reinstalled in the system. The conclusion for the high setpomt was stated in the CR to be "unauthonzed setpoint adjustment by personnel outssde of the scope of work controls " This was based on the fact that no hardware problems were found, cap and lever seals were missing, and the prevmus setpomt adjustment was witnessed by Quality Control (QC). The inspector rewowed the work order and the CR, and inspected the valve installed in the system. Numerous discussions were held with Maintenance personnel on the process j
of adjusting the setpomt. Conversations with kr-cif,;+able licensee personnel indicated that, on occasion in the past, the V2325 valve had been observed to Neop"
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or slightly leak past its seat.
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Conclusions
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Based on independent review of the documentaten and the fact that the valve spring i
tension was not adjusted to its highest setting, the inspectors concluded that j
tempering, although it could not be conclusively ruled out, was not likely to.have occuned in this spedlic case either. The more liialy cause for the tr===4* valve was due to unauthorized maintenance performed to stop the valve from weeping.
The inspectors concluded the licensee. adequately evaluated other similar valves to assure they could perform their intended function l
The inspectors verified through documentaten review, that the V2325 setpoet was l
adjusted, property tested and the valve reinstalled in the system.
l 02.1.3 Site Manaoement's Response to the May 1996 Event l
a.
Inspechon Scope i
l The inspectors reviewed the actens taken by site management in responding to the j
identillestion that relof valve V3483 on the Unit 1 LPSI pump discharge line might i
have exponenced tamponng to determine if management's response was =-;-- eg:^
l for the known cucumstances.
L b.
Observations and Findinos The inspectors reviewed CR, N5. 96-0890.~the Elfshows, on May 15,1996, V3683 l
failed to lift within 10 percent of its design setpont and addibonal testeg was requwed i
to determine the actual setpoint. The as-found setpoint was 55 percent above its i
design setpoiryt.
f j
Management's revow of the CR on May 17,1996, shows that Engmeenng was
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assqpned to. evaluate the potenbal that the 1 A LPSI piping had been cn.yit::mzod j
and System and Component Engmeeting was assigned to perform a root cause evaluabon of the valve's condition. The CR also contains the engineering evaluation I
of the possible overpressure condition and the root cause evaluaten showng that these assignments were completed on about May 22,1996, i
l CR 96-0890 documents that V3483 was found with its wire seal broken and wrapped
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around the valve cap. The CR identned that the first record of the seal condition was
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when the valve was in the drumming room where testmg was done on the valve.
j CR 96 0890 documents that addebonal actens were recommended includeg 1
determming "(1)... the course of schon that led to the misadjusted valve condition and (2)... that the plant perform a samping of lead seals on safety telated relief valves in j
both units to assure that this condition is isolated to this one case."
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CR 96-0890 docurients that Opershons Procedures OP-1-0010125A and j
OP-24010125A worm used to perform a watodown of all safety rehof vahms. The t
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inspectors reviewed Data Sheets #238 frorn Operations Procedures OP-1-0010125A, i
Revision 5 and OP-2-0010125A, Revision 4, and noted that a total of 150 safetyfretof j
valves were hated in those data shoots, t
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CR 960890 docurnents that ten Unit 1 and no Unit 2 valves were found with defident
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condibons. Ten Unit i valves had missing or broken semis.
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Documentation reviews show that CR 96-1247 was wntten at management's request to document the deficiencies on the 10 Unit 1 valves from the walkdown of the 150 i
safety and rehof valves and to disposition the deficsoncies. This CR also documents 3
an analysis which concludes the site pokcy on installabon of seals has been j
inconsistent. The analysis documents that a plant contractor's current prachce was to install seals following rebuildsng or testing but that installabon of seals was not j
addressed in sorne vendor instruchons used by the plant for valve maintenance.
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CR 96-1469 documents the plant evaluation performed on valve V2325 once the valve was determined to be about 9% greater than its design setbng on June 14,1996. The analysis conduded that setpoint drift was an unlikely cause for the increased setpoint and that a potential and most hkely cause was "unauthorned setpoint adjustment by l
personnel outskie the scope of work controls." The CR analysis also states that the plant's discaphne pohcy and management's expectation for verbatim procedure l
compliance were recently articulated and should eliminate future concems about unauthonzad work.
j Discussions with savoral site managers identified that management determined the as-found condidons of valves V3483 and V2325 were not hkely a result of personnel i
tampenng with the valves. This conclusion was contrary to the documentabon in the l
above CRs wtich stated the as found high rollef valve setpoents on valves V3483 and V2325 were ocasidered to be tampering or work control problems. The inspectors could not confirm the bases of those management decisions through any c-$-f=
l evidence. However, discussions with the NRC Senior Resadent inspector confirmed i
that he had been informed in the June 96 timeframe that site management had concluded that the root cause of the high as-found relief valve setpoints was not likely i
tampering.
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Discussions with site management, which were also confirmed by the NRC Senior i
Resident inspector, disclosed that site Security was to be informed of the potential l
tampenng events with valves V3483 and V2325. I.,uring this inspechon, the j
inspectors were informed by site management that site Security had not been informed as clirected. As a result, no heightened secunty awareness had been implemented. Discussions with site Security management and review of l
documentatico confirmed there were no acbons taken to increase the awareness of l
the site Security force.
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The inspedoes oboened the installed con 6gurabons of valves V3483 and V2325 j
during this innocbon, revowed drawngs of the valves, and discussed valve calibration, instanslion and operations with knowledgeable hoensee personnel. The l
inspedors obeened that, if there was an intent to disable the valves, there were d
easier and quicker ways for a imc;f: f-g M person to tamper with the valves without
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removal of the valve caps.
l c.
Conclusions i
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i The inspectors concluded that site management appropnately ' pursued identdication of j
the cause for rehof valve V3483 having a high setpoint. In addition, because of the 1
l broken wire valve seal, appropnate walkdowns were conducted to determee the extent of condition of possbie valve tampenng. Once the extent of condibon was l
established, management appropriately evaluated and disposeboned the deficencies.
l The inspectors concluded that tampenng with rehof valves V3483 and V2325 could not be corw*2d; ruled out based on the exishng evaluation documentabon.
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However, based on the team's dwect observabons, the inspectors also, concluded that site management reached a reasonable decision that, tampenng with valves V3483 and V2325 to intentionally damage them, was unkkely.
i 1
i Since tampering with the valves could not be conclusively ruled out management's.
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decision to alert Security of the tampenng possibiBty was appropriate. The inspectors i
j also concluded that fadure to follow through on alertmg site Security precluded actions to enhance secunty force awareness to other possible tampering events.
i O2.2 Summary of the July 1996 Lock Tamperina Event i.
On July 26,1996, at about 8:30 a.m., an entry door to the Unit 2 Control Element Dnve
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Mechanism Control System (CEDMCS) room could not be opened due to some foreign i
material in the lock. Subsequent evaluaten identified additional, examples of padlocks and l
door locks damaged by the insertion of foreign material into the lock cores.
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A total of nine padlocks and two door locks were found to be damaged by foreign material in l
the lock cores. The damaged locks were for the followng areas and equipment:
l Unit 2 CEDMCS room access door - 1 padlock, i
e Unit 2 floor hatch in.switchgear room - 2 padlocks, l
Roll-up door in the Unit 1 A Train Emergency Desel Generator (EDG) room -
l i padlock, i
Roll-up door in the Unit 1 B Train EDG room - 1 padlock,
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Security door module box inside the Unit 1 A Train EDG room - 2 padlocks, e
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e Security doors to Power Panel #254 - 1 padlock, l
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Secunty doors to Power Panel #255 - 1 padlock, i
l Unit 2 CEDMCS room - 1 door lock, and
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Unit 2 Sa%ty Assessment System computer room - 1 door lock.
l For exarr.& ;wroses, Figures 6-9 in Attachment 3 show, respectively, the Unit 2 floor hatch j
and locks. tow. en the doors to Power Panel #254, a roll up door in one of the EDG rooms l
and a close4.p ',ww of the lock on the cham for the roll-up door.
Except for access to Power Panels #254 and #255, tampering with the remaining locks had a l
harassment imped on the plant and had no impact on safe plant opershons. Power i
Panels #254 and #255 must be accessed in a timely manner to remove power to the i
Atmospheric Dump Valves (ADVs) so that, in the event a plant fire, the ADVs do not
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spuriously actuate.
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02.2.1 Evaluation and Correchon of Domened Components I
j a.
Inanechon Senne l
Revow licensee's evabation of the damaged components and correchon of the j
damage to the locks.
l b.
Observatens and Findenas The inspector revietved CR 96-1856, which documented that a padlock locatad Bh the l
CEDMCS room door could not be opened. This room is located withm the Unit 2 i
Cable Spreading Room. The CR stated that follow-up ir;;::^7'l:=i idenbfied a total of j
nine padlocks and two door locks which had been dmabled by havog a glue-like.
sutstance injected into the lock cores. In addition, the inspector vertiled through 3
j direct observabon and documentabon revew that the affected locks had been L
repaired. Subsequent checks by Security guards venfied the repaired locks operated property.
c.
Conclusions i
i The damaged locks were repaired and venfied operatonal.
02.2.2 Evaluation of Plant Systems for Addibonal Tarnperina l
a.
Inspechon Scope Verify plant safety systems had been sufficently evaluated for potential tampenng to i
assure they can perform their intended funchons.
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b.
Observations and Fsxhngs i
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The inspectors venfied through documentabon review that upon descovery of the i
damaged locks, the boonsee conducted iriaW of other locks throughout the i
plant. Secunty personnel opened and inspected security lods to verify that they were i
operabonal. Plant Opershons personnel vertRod that opwations locks for valves were j
operabonal. The licensee used Administrative Procedure 1/2 0010123, Administrative
' Control Of Valves, Lock and Switches, Revisions 101 and 73.W+f;f,, to verify thdse locks installed on valves.
Corporate Security was contacted and performed an independent investigation of the 3
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event. The ir;;::U:-3 was in progress prior to the August 14,1996 event.
l Approximately one week after the July 26,1996 event, the inveshgator informed the site that it was unlikely that they would find the perpetrator. Based on the event, Site l
Security was bnefed to heighten their awareness to detect other tampenng actMbes.
I c.
Conclusions.
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The inspectors concluded the licensee conducted an extenssve evalumbon to determine of other Secunty and Operabons padlocks would perform their funcbons.
j Although the licensee's response to the damaged locks was completed in a bmoly i
manner, the evaluation did not include the keylock switches on the HSDPs.
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02.2.3 Site Manaaement's Response to July 26.1996 Tamoenna Event 3
a.
Insoection Scoce Review site management's response to the tampenng event discovered on July 26, 1996, involvmg foreign material in secunty padlocks and room door locks, to determine if appropnate actions were taken.
b.
Observabons and Findinos CR 96-1856 documents that site security and Operations checked all pad locks and door locks cored specifically for security and Operabons purposes. Those checks included pad locks on locked valves. Addibonally, site Secunty heightened the security awareness of the Security force concoming possible additional tampering.
Officer visibility was increased in the affected areas.
Management requested in Corporate Security assistance. Corporate Security interviewed various plant managers to gain an understandag of the circumstances and took possession of several damaged pad locks for further analysis.
The subsequent discovery of damaged keylock switches indicated the checks done in response to this event were not expanded sufficiently.
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1 This ev nt was incorrectly=======i by management as not Wing reportable to NRC e
i under 10 CFR 73.
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Management's response to this event was not thorough in that keylock subches were j
i not checked for damage until August and the event should have been formally reported to NRC.
1 02.2.4 lmolomontaten of intenm Achons to Detect New Tamoonno a.
Inspection Scope i
2 Determme if adequate interim achons to detect new tampenng had been implemented.
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b.
Observatens and Findmos After identifying tampering on the CEDMCS door locks, the hcensee implemented an inspedon of other door locks, padlocks and locked valves at the site. A total of nine i
padlocks and two door locks were found to have been tampered. No safety concoms were identified by the heensee.
l' Site Secunty officers were briefed to heighten their awareness to detect other j
tampenng actmbes.
c.
Conclusens
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Idenbficaten of tampering of components within the vital area of the plant i
demonstrated that addsbonal taim could occur. Therefore, the hcenses should have considered additional measures to detect new tampenng of equipment at the site in addition to alertog the Secunty force.
S1.2.5 Secunty Investaaten of +he Event a.
Inspechon Scope Determee if the security and investigative staffs adequately revowed the event.
b.
Observabons and Findinos The Corporate invesbgator responded to the site on July 27,1996, to review the July 26,1996 tampenng event The inveshgator reviewed the lock locabons that were tampered with in the Flectncal Equipment Room (EER). Site Security provided a lod j
that had been tampered with for analysis and computer access logs for the time period that the suspected tampering occurred.
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c.
Conclusion i
l-The Corporate invesbgative staff #=gM renewed the event.
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i S1.2.7 Evalumbon of Comohance unth the Physcal Security Plan
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a.
Inspechon Scope i
i t
I Determme if the imensee was in compliance with their PSP and Procedures.
j I
10 CFR 73.71, Reportog of Safeguards Events, Appendix G. (3) Reportable l
Safeguards Events, requires the boensee to report to the NRC within one hour of i
discovery, followed by a wntten report within 30 days, events which cause terruption m
i of normal operatKms through tampering with controls including the secunty system.
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j b.
Observations and Fmdmos The hoonsee's Secunty Procedure, SP4006125, Reportmg of Safeguards Events, j
Revision 9, dated April 20,1995, Paragraph 8.2 (1) defines one of those events.as being a confirmed tampenng of suspeczous ongin with safety or secunty equipment."
i-On July 29,1996, the heenses failed to follow their procedure and report the j
j' confirmed tamponng with the secunty equipment (locks) within one hour to the NRC.
This is a violabon (VIO) of regulatory requirements (VIO 50-335/96-16-01, l
50-389/96-16 01, Failure to report an event to NRC within one hour).
t c.
Conclusion The licensee faded to comply with requirements for reportog the event to the NRC.
O2.3 Summarv of Anauet 1996 Event Concemina Damaae to Hot Shutdown Panel Keviock l
Switches
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i On August 14,1996, dering a monthly surveillance of the Unit 2 HSDP at about 10:00 a.m., a l
plant operator discovered two key switches could not be operated because foreign material
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precluded the insertson of the keys into their locks These were the only key switches on the Unit 2 HSDP. Each St. Lucie unit has an HSDP that was designed to be used to shutdown j
the unit froru outside the unit main control room. The two damaged key lock switches j
operated channels A and B, respectively, of the SlAS to block unwanted actuation of the i
Safety injedion (SI) system during unit cool down.
Upon idenbfication of the damaged UnM 2 key lock switches, a check of the HSDP for Unit 1 i
was conducted. The Unit 1 HSDP contained only one key syntch on the panel. Similar to Unit 2, that key lock switch could not be operated because of foreign material in the lock mechanism. The damaged key lock switch operated the pressunzer PORV which provides a
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backup means to control pnmary system pressure if auxiliary pressurizer spray becomes j
unavailable while bringing the unit to a controlled shutdown condition.
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15 02.3.1 Evaluatkm and ComMition of Damaaed Components a.
Inspectum. Scope Review beensee's evaluaten of the damaged components and correchon of the damage.
b.
Observatens and Findenas CR 96-1994 documented that PORV 1404 keylock control switch, CS 117, located on the Unit 1 Hot Shutdown Control Panel (HSDCP) and SlAS Bypass Switches channels "A" and "B," CS 246-3 and CS 248-3 isspecttM, were found to be inoperable due to i
foreign material in the lock core whch prevented key insertion. An inspector observed the damaged switches while still installed on the HSDCP and noted that a foreign substance was not vmble.
The inspectors reviewed Work Order 96020830 which documented the replacement of the inoperable Unit 1 PORV switch. Pnor to installation the new switch was tested for contmusty. Dunng instatisten, the two wres attached to the old switch were llRed and relanded on the same terminal connectens and independently verthed to be conect.
Following instalisten of the switch, an inspector venhed the wres were landed on the appropnate terminals. An inspedor reviewed Work Order 96020826 which documented the replacement of the inoperable Unit 2 "A" and "B" channel SIAS bypass switches. Following installation of the new switches, portions of I & C Procedure 2-1400052, Engineered Safeguards Actuation System - Channel Functonal Test, Resiiision 23, were performed as a poiit maTnisnance test to venfy operabiNy.
This test operated each switch and verified the appropriate response was obtained.
An inspector witnessed the performance of this test and verified it was sabsfactorily completed.
c.
Conclusions The inoperable Unit 1 PORV control switch and the Unit 2 "A" and "B" channel SlAS bypass switches were replaced and operability was adequately verified.
O2.3.2 Evaluation of Plant Systems for Additional Tamperina a.
Inspection Scope Verify plant safety systems had been sufficently evaluated for potential tampenng to assure they can perform their intended functons. NRC provided intamal correspondence to the boensee regarding an appropnate approach to be used to evaluate the tampenng event. This information is contained in Attachment B to this inspection report.
I e
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b.
Observations and Findinos On August 14,1996, the heensee checked all accessible keylock switches and locked valves located in both unit control rooms and in the neid by inserting the appropriate i
key and verifying no foreign substance had been injected which would prevent i
operation. Those locks excluded from this check because of limited accessildity were locks located in the reactor containment buikhng, the annulus, and high radiation j
areas. The inspector reviewed the re,vva documentation of Admirweerative j
Procedure 1/2-0010123, Administrative Control Of Valves, Locks, And Switches,.
Revisions 101 and 73 respectively, and venfied required schons had been appropriately completed with no abnormalities identl6ed.
l On August 15,1996, the hcensee conducted visual inspections of selected areas in j
both unit control rooms includmg inside catxnets, panels, and boards assocated with safetydeleted fundions, loolang for unexpeded foreign matonal, undocumented j
ju,vW.M inads, or any otmous faults. No abnormalibes were found. The inspectors veriSed this had been completed through doczamentation renew and intennows of personnel. No abnormalities were noted. However, the inspectors determined that there were areas within both units' control rooms that had not been l_
inspected. These areas were those outside of the area morutored by the licensed operators, such as, the lutchens, Technical Support Center, ofilces, and ventilation j
rooms. The inspectors verified that ttese areas were inspected on August 21. No j
abnormalities found.
i l
In addsbon, on August 15,1996, the licensee performed usual mspechons of both -
1 units in thE areas o'f: Reactor Buildings, TdibineTulldings, intake areas, Condensate i
Storage Tanks, Fuel Handling Buildings, Component Coohng Water (CCW) areas, Ultimate Heat Sink area, Diesel Generator buskhngs, Intake and Dacharge Canal Headwalls, Blowdown buskhng, and Auxihary Feedwater Bulldogs, and Steam Trestles, looking for abnormalities or foreign matenals. Both units' Containments were venfied to have been locked or have had entry only under the two man rule since i
July 26,1996. Through documentation reviews and intennews of personnel i-performing the inspections the inspectors concluded that no abnormalities had been identified dunng these inspechons, in addsbon, the inspectors independently conducted wsual inspechons/walkdowns of the followmg areas for both units: Main Control rooms, ECCS Pump rooms, Reactor Auxiliary Buildings including the pipe l
tunnels and penetrabon rooms, Auxiliary Feedwater Buildings, Cable Spreading i
rooms, Turbine buildings, EDG Buildings, and the outside yard. No abnormalities i
were identified.
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The licensee performed visual inspections of pepmg and valves on both units to i
idenbfy obvious signs of tampenng such as cut chains or locks, loosened hardware or
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fittogs, blockage in air boxes, missing bolbng, and missing supports for the following l
systems: Venblaton, Sennce and Instrument Air, HPSI, LPSI, Containment Spray, J
Blowdown, Condenser Circulating Water, EDGs including Fuel Oil, Condensate and
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Feedwater, Heater Drains, Auxiliary Feedwater, Fire Suppression, Main Steam, Extraction Steam, Auxiliary Steam, Turbine and Support systems, Lube Oil, Waste j
Management, Water Treatment Plant, Chemical and Volume Control, Service Water,
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1 Post Accident Sampling, Sewage Treatment, Pnmary Water, Hypochlorths, Gas
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House, intake Cooling Water (ICW), and verlous support systems. Through i
documentation reviews and interviews of personnel performing the inspedions, the i
inspectors concluded that no abnormauties had been idendhed during these 1
inspections. In addition, the inspectors independeney performed visual ir=r-*ans of l
' piping and valves on both units to identify any abnormemes associated with the i
following systems:.HPSI, LPSI, Containment Spray, Charging Pumps, Auxiliary 4
Feedwater, CCW, Safety Related Switchgear, and EDGs systems. No abnormalities -
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were identified.
i i
l The licensee performed visual checks to confirm electncal power system integrity j
looking for such thmgs as equipment which may have been tampered with as t
evidenced by switch mechanisms altered, coohng fan blockage, panel access altered, I-connection boltmg loosened, breaker raddng mechanisms altered, unauthorned grounds, foreign objects present, or any condition which could s.,T,,,,w,, ' the integrity of the power system. Subsystems inspected were: EDGs,6.9KV and 4.2KV sutchgear, Switchyard, Main transformers, Auxikary transformers, Start up i
transformers, Load Center transformers, 480V load contors and Motor Control j
Centers, Battenes and Chargers, DC load contors, inverters, Motor-Generator Sets, j
and Voltage Regulators. Through documentabon and interviews of personnel i
performing the inspechons the inspectors concluded that no abnormahties had been j
identified dunng these inspections. In addition, the inspectors performed independent visual checks of the safety-reisted nfC and motor control centers to verify that power was available to both the breakers and charging spring motors. Extemal inspechons were also conducted of the valve motors associated with each of the i
safety sysfems that'the inspect 6ts'inspectsd7 l
The licensee performed inspechons of both units' HSDCP looking for otwoous signs of l
tampenng such as loose wmng or switches, uncontrolled substances appised to winng connechons or switches, and proper response of instrumentation. The inspectors reviewed the Operstmg Procedure (OP) for both units which documented proper l
j operation of instrumentation and alignment of switches,.1 and 2-0030151, "Remotd l
Shutdown Monstonng instrumentabon Periodic Channel Check And Selector Switch Position Verification," Revisions 30 and 20 respectNdi. In addition, the inspectors i
independently inspected both units' HSDCP to identify the presence of foreign material or signs of obvious tampering..No abnormalities were identified
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The licensee completed detailed safety system examinations on both units. Technical i
Specificidicn requirements were used as the overall acceptance criteria.
i l.
Exammations included performmg major system flowpath verifications, operational
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runs of related equipment (e.g., starting pumps), visual inspections, and selected instrumentabon trend reviews of the folloung:
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Pumps Started: HPSI, LPSI, Containment Spray, CCW, ICW, Auxiliary
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Feedwater, Fire Suppression, Fuel Pool Coolmg.
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EDGs were started and Reactor Protection System trip circuit breakers were i
visually inspected.
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i Major flow path verifications (maior valve position and electrical lineups) were done for. AuxNiery Feedwater, CCW, ICW, HPSI, LPSI, Containment Spray, i
Chemical and Volume Control, Fire Suppression systems.
l in addition, the beenses verified the Normal /Isolete switches to be in the Normal possbon, proper Thermal Overload Bypass switch positions, and proper opersbon of
. Emergency Lightmg.
The inspectors witnessed / verified valve lineups for both units on the following systems: HPSI, LPSI, Containment Spray, and CCW. In addibon, the inspectors j
i reviewed completed documentabon for both units which indicated that operational
^
pump runs were performed by the hcensee for HPSI, LPSI, EDGs, and Containment Spray systems. No abnormalities were identified.
l An inspector reviewed the hcensee's Off-Normal procedure for both units which control the plant from the HSDCP, " Control Room inaccessibihty," 1/2-0030135, l
Revisions 24 and 23 se -;+ ";;V. In addition, the inspectors performed a field venfication of the procedure and components operated with the assistance of a licensed operator. Dunng this walkdown, the inspectors found keys used for the i
control of Normal /Isolete switches associated with Unit 2 PORVs V1474 and V1475 located in unlocked cubicios which house the switches. These aMaa are located in the 2A and 2B electrical penetrat6on rooms of the Reactor Auxshery Buikhng and are maintained closed by a hasp-type mechanism. The operator assisting the inspectors informed the Control Room staff. The keys were secared and Opershons initiated CR 96-2087 to document the problem and develop corrective acbons. Administrative ProceduisNo. 2Jo010123,'"Adrmhistr'ative ContRil Of Valves, Locks And Switcins,"
Revision 73, step 8.2.1 requires that cubicles containing cnbcal controls in remote locations shall be locked and the keys mantained under Adrmnistrative Control. This was not done in this case and represents a violabon of procedural requirements.
(VIO 50-335/96-16-02, 50-389/96-16 02, Failure To Ad+g-Mi Control Operations Keys).
From August 15-23,'1996, the inspectors observed the licensee's additional secunty force schons to detect or prevent new tampenng during both day and night operations. Additionally, the inspectors reviewed the procedures for the added security functions and observed the verbal shift briefings.
The inspectors also noted that at approximately 5:00 p.m., on August 14,1996, that the licensee assigned other plant personnel to duties as observers / patrol officers in specific areas within the plant. These personnel were placed in the area as a deterrent to prevent additional tampering with equipment. The inspectors determined that prior to the personnel being assigned to the observer duties they were verbally instructed to observe personnel entenng the area and that if any personnel appeared suspicious to notify security. The personnel that were assigned to perform as observers did not consider their training for this type funcbon to be adequate. On August 16,1996, the licensee provided the patrols and observers with a written flyer as instruebons. The flyer contained the following instruchons: Question the activities that are going on in their area of surveillance / responsibility; ensure obscvations of
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these actMties is frequent and random; ensure that the people working in these areas l
feel that they are under surves11ance; this wlN ensure that the observers presence would prevent tampering with equipment; and, should the patrol ofRoershboorvers encounter any personnel or actMties that do not appear proper, contact tne security Operations Officer. At approximately 5:30 p.m., August 15,1996, the licensee l
terminated the observer function.
The inspectors independently reviewed the CRs initiated smos April 1996, to identify j
additional tampenng events.' This inspection included a documentation review of i
approximately 1500 CRs. No additenal tampering events were identi6ed. In addition, i
the inspectors reviewed the Work Orders initiated dunng the penod of July 20 -
August 19,1996, to determme if the cause of the identiRed problem was tamper related. This evaluation included a review of documentation, interviews with
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maintenance workers responsible for completing selected Work Orders, and field observations of several affected components. This review did not identify any I
additional tamper related problems.
c.
Conclusions i
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The inspectors concluded there was no evidence of additional tampering and that the licensee had ="==My evaluated plant safety systems to assure they were able l
perform their intended function.
j O2.3.3 Site Manaaement's Response to the Auaust 14 Tamper Event
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a.
Insoectics Scoce '
i The inspectors' objective was to assess whether site management adequately i
responded to the tampering of key lock switches discovered on August 14,1996.
b.
ObseiwMns and Findinos l
In response to the detection of the' damaged liey lock switches, site management l
reported the damaged switches to the NRC in accorda'nce with 10 CFR 73 within
. about one hour of the discovery of the damage.
A Security Alert was declared by site management. Declaration of Secunty Alert resulted in the site meeting an Emergency Action Level established in the site Emergency Plan for the declaration of a Notification of Unusual Event (NOUE). A NOUE was deciated and reported to state and local authoribes arm to the NRC.
Site management also notified their other nuclear plant at Turkey Point.
Management directed plant personnel conduct visual inspechons of important plant structures to look for any abnormal conditions or foreign material. Some general areas were intentionally excluded from these examinstens based on established assess control and/or radiation exposure considerations.
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'20 Management dwected that visual checks be conducted, for both units, of a.4 4 l
portens of the unit Control Rooms and of pipeg and valves, pumps, motors and instrumentaban assocsated with imponent plant systems includmg plant safety systems. A C'=ri, electrical power systems were visually checked for abnormal condetions. In response to subsequent di====ians with the inspectors, hoensee l
personnel completed additenal visual checks of areas adjacent to the control rooms j
on Au0ust 21,1996.
l Management directed addebonal checks be done to assure important systems were j
operabonal by operatmg important purrps and checking locked valves and valve l-possbons in flow paths of major systems.
l On August 14,1996, site management held a setowide " stand-down" to alert site personnel to the apparent tampering, the seriousness of such acts and to sohcst informabon about the lock damage found on August 14,1996c i
Management also issued a night order to plant operators to be on the alert for addifonal examples of tampering.
Management implemented a review of CRs issued since May 22,1996, for additional examples of tampenng. Additional examples identilled included the May 1996 rehof valves and the July 26 lock damage described earter in this report. The inspeders
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also independently reviewed approximately 1500 CRs dating back to earfy April 1996 and no addstional examples of tempenng were identilled.
Managerrient did 'n6t evaluate recent work"ortierft)6nerated by plant personnelW were not part of the CR system, for addibonal examples of tampering. At the request of the inspectors, a listing containing a desenption of NPWO, initiated between July 20 and August 19,1996, was generated for each unit. Review of that information by plant personnel did not identfy any additional examples of tampering. The inspedors' independent review of that documentabon and direct inspecten of selected damaged components, also did not reveal any examples of tampenng The inspectors also revewed Radiological Event Reports and Radiological Deficiency Reports generated since January 1,1996 through August 1996 for examples of unauthonzed workers found working in high radiation areas. These were areas exempted by site management from visual plant walkdowns. No abnormalities were identified.
Management requested that Corporate Security it;r:%:te the August 14 additional examples of tampering.
Site Security posts and patrois were expanded to heighten Security officer visibility and checks of ongoing work in the plant.
Site management periodically briefed NRC management regarding the actions they were taking and were planning to take, i
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Utilltv nionagement offered a $10,000 reward for information meding to the anset and I
convmtion of anyone responsible for the damage to inck up safety switches".
Television monitors through out the plant carried that message.
Except for the Security aeons and Operations night order identined above, management did not implement adelonal interim amans aimed at decedmg new j
cases of tampering in a timely manner. Following rumaW with.the, inspectors, j
. management developed a plan to periodically asenes plant areas and systems unng kncif.::"- plant staff. These checks were in additen to those routme and specal checks being done by the Security Of5cers.
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C.
Conclusions Site management satisfactorily evaluated, consstent with the known examples of tampering, the opershonal n'ar=himy of the plant safety systems to perform their l
intended asfoty functions.
Site management '=":' A-ti evaluated plant areas for foreign matenal and abnormailbes.
Site management could have used addibonal plant documentation of equipment deficencies in its search for additional examples of tampenng.
Site management could have been more proactive in = ^f'2 intenm actions to 9
detect new tampenng by usmg plant staff as well as Secunty.
O2.3.4 Imolementation of interim Actions to Detect New Tamoenna a.
Inspechon Scoce Determme if adequate interim actions to detect new tampering had been implemented.
b.
Observatens and Fmdinos Between August 15-23,1996, the inspectors observed the licensee's additional security force acbons to detect or prevent new tampenng during both day and night operabons. Addebonally, the inspectors revewed the procedures for the added security funcbons and observed several shift briefings.
Initial discussions between plant personnel and the inspectors indicated that intenm measures to increase the probability of detectog new tampering, other than in the area of secunty patrols, had et been consulered. Followng those discussions, the licensee concluded that addibonal measures were prudent. The followng schons were implemented or being planned at the conclusion of the inspechon Ongong Plant inspections - An existing program, the Plant Material Condition inspection Program, was expanded to specifically include looking for evidence i
of tampering as part of the required inspechons. This program consists of 38
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inspectors assigned to inspect on a frequent beeis (apprommately daty) specdic areas of the plant for matenal condition. The results of the inspectens i
are required to be documented weeldy.
Plant CRs and NPWO win be reviewed on a daily basis for defects or conditens which could have resulted from tampenng i
System Engineers were instruded to specificany indude inspections for l
evidence of tampenng as part of their routmo system walkdowns and inspectens. Managers performing required off hour tours were to be instructed to include similar inspections as part of their dubes.
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Operational checks of speafic equipment were to be performed as appropriate to assure proper operation. The appropnate frequency for these checks wiu be L
estabbshed by senior plant management usmg assessments of the rer.Lets of l
the ongoing investigston, inspections, and plant operatonal status.
The hcensee indicated that the duraten of the above actpons hvould be based on the'results of plant inspechons and the security k;r";f =i. Any decision on changes in scope and changes in durabon of the actens would be made by senior plant management after docussions with NRC.
c.
Conclusions The security force implemented good preventative measures to detect or prevent new tampering with plant equipment. " -
~~ "-
The inspectors concluded that the actions specified in Secten 02.3.4, if property implemented, would provide reasonable assurance that new tampering, if it should occur, would be promptly detected. Implementaten of the interim schons is identified as an IFl (IFl 50-335/96-16-03, 50-389/96-16-03, implementation of interim Plant Achons to Detect New Tampering).
S1.3.5 Security Investiaaten of Event a.
Inspection Scoce Review the investigative efforts of the licensee.
b.
Observatens and Fmdmos The hcensee assembled a very well trained and experienced investgative team to review the tampering events. The investgators included a highly skilled consultant as part of the effort to determine who the individual was that had been involved in the lock tampering event.
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c.
Conclusion 4
The hcensee took appropnate and extenswo efforts to determine the indwidual(s) i invoked in the lock tampering event (s).
l 02.3.8 Plant Licensmo Bass i
a.
Inspection Scone 9
4 Determee the beensing base for the HSDPs for St. Lucie Units 1 and 2.
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inspect the installed HSDPs against the desenption in the FSAR and UFSAR. Idenbfy any deviations between the installed equipment and the description in the FSAR.
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Observabons and Findinas i
l The FSAR for St. Lucie Unit 1 was sutetted 'on February 28,1973. Section 7.4.1.8 described the controis and instrumentation to bring and maintain the plant at hot standby from outside the Control Room. The design at that time did not include a j
separate remote shutdown panel, but rather had operators control the plant from local l
stations in the plant. The bcensee amended the description of the Unit i remote l
shutdown cal =hMay in Amendment 51 to the FSAR sutetled on October 10,1975.
j This -t A". includes a HSDP located at Elevabon 43 ft. of the Reactor Auxiliary i
Buildmg. The FSAR description (Amendrnent 51) has remained essenhally
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unchanged, with the excephon of the addition of the key lock switch for the PORV and -
a switch f6' the POIRV Block valve'. ~ Ameriddien(Tfo the UFSAR in July 1986 '
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i documented this change. The plant license references the FSAR through Amendment 57, and thus the desenphon of the HSDP in Amendment 51 is part of the original Unit l
1 hcensmg basis.
L The inspector performed a walk-down of the Unit 1 HSDP to determine if the installed controls and indications conformed to the desenphon in the FSAR. The following -
deficiencies were noted:.
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The FSAR (and UFSAR) listed one control switch for the pressurizer auxiliary spray valve. There were two switches installed on the panel.
i There were two Nuclear instrument wide range indicators and two source range Nuclear Instrument indicators installed on the panel. Nesther the FSAR 1
nor the UFSAR, included these indicators on the list of instruments installed on the HSDP.
i it was also noted that the description of some of the controls and instruments in the j
UFSAR could be revned to more clearly desenbe the instrument installed on the HSDP.
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The FSAR for St. Lucie Unit 2 was submitted to the NRC on March 24,1980.
Section 7.4.1.5 of the FSAR described the controis and instrumentabon to place the
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plant in hot shutdown and, if necessary, cold shutdown, from outside the control room.
l The design included a HSDP, and Table 7.4-2 hated the controis and indications i
provided on the HSDP. "the location of the HSDP was specilled as a room in the southwest comer of the reactor auxiliary buddag at Elevation 43 ft. The NRC i
acceptance of this design was documented in an SER dated October 9,1981.
i Subsequeney, the licensee provided additional informabon related to allemative shutdown capability as requwed by 10 CFR 50, Appendix R. The NRC, in l
Supplemental SER 3 dated April 6,1983, found that the altamative shutdown capability at St. Lucie Unit 2 was in compliance with the guidehnes of Sechon Ill.L of Appendoc R and was, therefore, acceptable. Subsequent updates of the Unit 2 UFSAR under 10 CFR 50.5g provided greater dotad in the desenption of the process for shutdown of the plant imm outside the control room, but did not result in any significant change in the design of the HSDP.
An inspechon of the Unit 2 HSDP revealed no deviations from the descnpbon in the FSAR.
Access control to the HSDPs for Units 1 and 2 was reviewed. The HSDP room for each unit was located in the respechve Reactor Auxiliary Budding on the 43 ft.
elevabon in the EER for that unit. This EER was a vital area and required key card access. The doors to the HSDP rooms were not locked. Since the rooms were located within a vitall area, this level of access control was determined to meet the St.
Lucie Secunty Plan.
c.
Conclusions The design and installaten of the HSDP for St. Lucie Units 1 and 2 were in accordance with the'iicenseg basis of the plants with the followng excephon. The FSAR descriphon of the controls and instruments installed on the HSDP for St. Lucie Unit i did.not match the equipment actually installed on'the panel. The FSAR did not desenbe the installed nuclear instruments. The. failure of the FSAR to correctly.
desenbe the installed equipment is identified as an URI pending additional licensee and NRC review (URI 50-335/96-16-04, FSAR Description of Installed Instrumentation on Unit i HSDP).
Control of access to the HSDP rooms of St. Lucie Units 1 and 2 was in accordance with the approved PSP for the site.
S1.3.7 Evaluation of Comohance with Physical Security Plan a.
Insoection Scope Determine if the licensee complied with the PSP.
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Observabons and Findwas j
j To preclude indMduals from being authonzed access to the faceuty who may engage in tampenng with equipment actMties, the licensee established a screening program in accordance with 10 CFR73.56 requwements. The PSP requires that, "AN i
indwiduals selected for employment with FPL who requwe access to a FPL nuclear j
plant are screened in accordance with the provisions of the Nucisar DMaion Access Authortzabon program and are subject to the company's Fitness.Por Duty Proy. ri.."
All elements of Regulatory Guide 5.66," Access Authonzation Program for Nuclear l
Power Plants," were implemented to sabsfy the requirements of 10 CFR 73.56." The PSP also required, that " contractor employees requesteg unescorted access are j.
subject to the provisions desenbod above and are included in the Company's Fitness l
for Duty Prov r.."
i The PSP further required that, "all Vial Areas shaN be locked and protected with an l
activated intrusion alarm system. Access to Vital Areas is controlled by card readore i
or a member of the security force (MSF). When access is controNed by MSF, Access
{
Authonzation shaN be venfled against a list containing the indMdual's name, badge number and access code. Once authonzation is ven6ed, MSF shaN record the individual's badge number, time in, and time out. Postwo Access Control shaN be afforded at aN Vtal Area entry portals via card reader except for Contamment which shaN be manned by a member of the Security Force when opened. Only those individuals with idenb6ed need for access and having +g v,,,' ^: authorization, shaN be granted unescorted Vdal Area access. Authortzstion for access to Vital Area (s) j shall be approved by the Plant General Manager or his designee. Vitt.1 Ama access l
lists shall 5e' approved by the ' Plant GinneraFMa6agir at least every thirty-one ($1) j days."
i-c.
Conclusion The licensee was in compliance with the site PSP regarding access controls, patrols, i
alarm station operations, fitness for duty and access authorization.
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INSPECTION PROCEDURES USED
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IP 62703:
Maintenance Observation IP 71707:
Plant Operations IP 81601:
Safeguards Contmgency Plan implementation Renew I
iP 92901:
Followup - Plant Opershons i
ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-335,389/96-16-01 VIO Failure to report an event to NRC within one hour, Paragraph S1.2.7.b 50-335,389/96-16-02 VIO Failure To Adequately Control Operations Keys, Paragraph 02.3.2.b 50-335,389/96-16/03 IFl Implementation of Interim Plant Actions to Detect New Tampering, Paragraph 02.3.4.c 50-335/96-16-04 URI FSAR Desenpbon of installed instrumentabon on Unit 1.
HSDP, Paragraph 02.3.6.c w
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X1 Exit Meeting Summary 1
j The inspectors presented the inspechon results to members of hoensee management at the i
conclusion of the inspechon on August 23,1996. The licensee a&c;if-;+1 the findings 4
presented.
a The inspectors asked the licensee whether any matenals. exammed during the inspection l
'should be considered proprietary. No proprietary information was identified.
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28 PARTIAL LIST OF PERSONS CONTACTED
' Licensee Bladow, W., Site Qualty Manager Brady, J., Corporate Communications j
Burton, C. Site Services Manager Noznesky, D., Corporate Security Pelt, C. A., Shift Technical Advisor Supervisor i
Scarola, J., St. Lucie Plant General Manager i
Stall, J. A., Site Vice President Weinkam, E., Licensing Manager White, W. G., Site Security Supervisor Other licensee employees contacted included operations, engineering, licensing, maintenance, and corporate personnel.
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LIST OF ACRONYMS USED t
j ADV Atmospheric Dump Valve 4
CCW Component Coolmg Water CEDMCS Control Element Drive Mechanism Control System j
CFR Code of Federal Regulations i,,
CR Condition Report EDG Emergency Desel Generator EER Electncal Equipment Room i
FPL The Florida Power & Light Company gpm Gallon (s) Per Minute (flow rate) l HPSI High Pressure Safety injechon (system)
HSDCP Hot Shutdown Control Panel HSDP Hot Shutdown Panel j
ICW Intake Cooling Water i
IFl-
[NRC] Inspector Follow item i
LPSI Low Pressure Safety injection (system)
NOUE' Notdicabon of Unusual Event
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NPWO Nuclear Plant Work Order NRC Nuclear Regulatory Commesson OP Operstmg Procedure PM Plant Manager PORV-Power Operated Relief Valve PSP Physical Security Plan-
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QC Quality Control
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SI Safety injechon l
SIAS Safety injechon Actuation System.
l UFSAR Updated Final Safety Analysis Report I
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URI.
[NRC] Unresolved item j
V volt.
4 VIO violation I
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Chronokgical Sequence of Events l
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MAY 16,1996 Licensee penouic testmg identified that the 1 A LPSI pump discharge relief l
valve V3483 lift setpoint was high (greater than 10 percent above design).
CR 96-0890 C;:':-;+1 to evaluate the condibon. CR 96 0890 also i
documented the broken lead seal on the valve.
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MAY 17,1996 Licensee identified valve V3483 lift set point about 55 percent above desagn value.
MAY 22,1996 Licensee Engineering evaluation and root cause analysis for SDC valve V3483 high lift setpoint determined "apparently due to tampenng or misadjustment of the valve's set screw controllag the spnng tension."
Recommendation made in CR 96-890 to examine a sample of lead seals on other safety related relief valves in both units.
j JUNE 4,1996 Licensee response to the broken lead seal found on valve V3483 on May 15,1996, was'en inspection of the seals of 150 additional relief valves on Units 1 and 2. This inspection was s,. -;':2 j and documented on CR 96-1247. Ten Unit i valves were identified with broken seals as well as some other visual deficiencies. No Unit 2 rehof valves were found with seal deficiencies. CR also documented that only valve V2325, one of the ten Unit 1 valves found with deficient seals, was found to have a high pressure setpont. The setpoet was 9 percent above the design value and within the 10 percent allowance band used to determme a need for an
._ overpressure evaluation. Valve V232!yss the relief valve on the 14.
Charging Pump discharge line.
JUNE 17,1996 Licensee initiated CR 96-1469 to determine root cause for high setpoint on valve V2325.
JUNE 27,1996.CR 96-1247 was closed out with the following results. Of the 150 valves tested:
10 Unit i valves were identified witti a damaged or missing seal wire (three had the seal wire damaged but intact, five had proper lift setting verified by bolt position, one had proper lift settmg venfied by bench test, and one had lift setting approximately 9 percent high--the 1B Charging Pump discharge relief valve, V2325).
JUNE 1996 Licensee management determmed the rehof valve deficiencies were not
)
likely to be due to tampering. The NRC Senior Resident inspector j
informed of the licensee's conclusion by the Site V.P. Site Secunty manager was not informed about the potential tampering as directed by Site V. P.
JULY 19,1996 Licensee closed out CR 96-1469 which documented the root cause for the high setpoint on the Charging Pump relief valve, V2325, as " unauthorized setpomt adjustment by personnel outside of the scope of work controls."
A-1, Attachment A.
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JULY 26,1996 At about 8:30 a.m., Operations could not open a padlock on the CEDMCS room which is located withm the Unit 2 Cable Spreadmg area. The i
padlock was damaged by apparent foregn material inside the lock core.
i JULY 26,1996 Subsequent investigation identified a total of nine padlocks and 2 door l
locks which had been disabled by having a foreign matenal injected into
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the cores of the locks. Locks found damaged were:
1 i
,1 padlock on the Unit 2 CEDMCS room, l
2 padlocks on a Unit 2 floor. hatch in the switchgear room, j
_1 padlock on the roll-up door in the Unit 1A Train EDG
- room, 1 padlock on the roll-up door in the Unit 1B Train EDG
- room, i
2 padlocks on the Security door module box inside the Unit 1A l
Train EDG room, 1 padlock on the doors to Power Panel #254 on -0.5'
- level, j
1 padlock on the doors to Power Panel #255 on -0.5'
- level, 1 door lock to the Unit 2 CEDMCS room, 1 door lock to the Unit 2 Safety Assessment System (Computer room.
JULY 26,1996 Licensee replaced cores of the nine padlocks and two door locks which had been identified as being damaged by tampering.
JULY 26,1996 Operations completed a check of alllocked valves in Units 1 and 2 for
_ foreign material.in the locks. Areas excluded from this evaluation, facesch unit, were the reactor containment building, annulus and high radiation areas. No additionallocks were identified containing foreign material.
JULY 26,1996 No formal report to the NRC Headquarters Opersbons conter made by licensee conceming this event.
l AUGUST 14,1996 At 11:15 a.m., while conducting a monthly functional surveillance, l&C Maintenance workers discovered two keylock switches had been disabled by having a foregn material injected in the lock cores. The two switches were located on the Unit 2 HSDCP and operated the "A" and "B" channel of the SlAS Bypass funchon. Because tampering was suspected, the Unit 1 HSCP was inspected and an additional keylock switch was identified to have been similarty tampered with. This switch operated PORV V1404.
CR 96-1994 was initiated to document the event.
At 12:12 p.m. the licensee reported the event to the NRC Operations Center via the Emergency Notification System in accordance with 10 CFR 73.71.
At 1:30 p.m., Security established additional posts in the affected areas and near other safety related equipment.
A-2, Attachment A
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At 1:34 p.m., Secunty Alert was declared. Vehicle and visitor access were restricted._ Safeguards contingency plan requirements were impismonted L
in additen to the Security posts==*=hs=hed in the aNected areas.
i At 1:46 p.m., the site declared a NOUE due to declaration of the Security i
Alert.
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At 1:55 p.m., Turkey Point notified of the event at St. Lucie.
l (Aftsmoon) NRC Resident inspector visually inspected damaged keylock switches. Foreign substance was not veible in the key locks.
l At 2:35 p.m., Security initiated check of au vital door locks to determee if any addebonal tampering had taken place. Operations was checkmg aN other switches and related safety equipment.
The licensee completed evaluation of all keylock switches and locked
}
valves located in both unit Control Rooms and in the fleid by assunng keys could be inserted into the lock core to venfy that no foreign substance had i
been injected which would prevent operation. No abnormalities were i
identified.
i At 3:00 p.m., the hcensee conducted a "standdown" of all site personnel to inform them of the event and encourage anyone with informahon to report it to either FPL or the NRC.
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At 3:12 p.m., all visitors were offsite.
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AUGUST 14,19R
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j At 3:15 p.m., plant Maintenance replaced Unit 2 keylock j
switches for the "A" and "B" SIAS Bypass in accordance with Work Order i
96020826 and performed post mamtenance testmg in accordance with I &
C Procedure 2-1400052, " Engineered Safeguards Actuation System -
. Channel Funcbonal Test."
j AUGUST 14,1996 Licensee replaced PORV V1404 keylock switch located on the Unit 1 l
HSDP. This is the switch which had been damaged due to tampering.
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The work was performed in accordance with Work Order 96020830. The post-mantenance test consisted of a bench test of the switch and an independent visual verification of the electrical _ lead landings.
(Afternoon) NRC Resident inspector witnessed portens of post-maintenance testmg of the Unit 2 "A" and "B" SIAS Bypass switches located on the HSCP.
4 At 3:30 p.m., licensee established two man rule for security post in auxiliary feedwater/ steam trestle, 0.5' Area, and the cable spreading room j
in each unit auxiliary building i
At'3:39 p.m., FBI agent amved onsite.
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A-3, Attachment A
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At 3:45 p.m., l&C was working on changing out Unit 1 HSDP Room damaged PORV keylock switch.
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At 4:11 p.m., checks of all security vital area doors and locks completsd; no discrepenaos noted.
l At 5:00 p.m., the boensee assigned other plant non escurity personnel to j
patrol in specWic areas within the plant. These personnel were placed in-the area as a detemmt to prevent additional tampering with equipment.
4 When the pessonnel were assigned to the areas they were verbelly instructed that they were to observe personnel entering the area and that if l
the personnel appeared mar =cirw= to notify secunty. These personnel indicated to the NRC during a walkdown that they were not trained for this j
tjoe funchon and that they had not been prmnded written instruchons. On August 15,19g6, the licensee provided the non-security personnel petrois i
with a written flyer as instruchons. After the flyer was issued the patrols j
informed the NRC that the instruebons were not adequate.
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~At 5:18 p.m., Security Alert Terminated. Turkey Point advised.
1 At 5:20 p.m., Television media amvod at plant. (See mode coverage.)
i At 5:30 p.m., NOUE terminated.
At 7:30 p.m., Secunty removed last of the 11 damaged lock sets.
AUGUST 15,19,96 Licensee commenced visual inspection of selected areas in both unit Control Rooms including inside cabinets, panels, and boards===aciated with safety-related funchons, loolung for unexpected foreign material, undocumented jumperallifted leads, or any otmous fault. No abnormalities found.
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AUGUST 15,1996
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Licensee commenced visual inspection.of both units looldng for abnormalities or foreign materials. Areas inspected were Reactor j
buildings, Turtune buildings, Intake areas, Condensate Storage Tanks, Fuel Handling bu,ldogs, CCW areas, Ultimate Heat Sink area, Diesel Generator buildings, intake and Discharge Canal Headwalls, Blowdown building, and Auxiliary Feedwater buildings and Steam Trestles.
Licensee venfied that both reactor containment buildings have been locked or have had entry only under the two man rule since July 26,1996.
Licensee comment:ed visualinspechons of piping and valves on both units to identify otmous signs of tampering such as cut chains or lockh, loosened hardware or fittags, blockage in air boxes, mesing bolbng, and missing supports. The following systems were inspected: Auxihary Feedwater, HPSI, LPSI, Containment Spray, Blowdown, Condenser Circulatmg Water, Ventilation, Service and In*ument Air, EDGs including A-4, Attachment A
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Fuel 05, Condensate and Foodwater, Hooter Drains, Fire Suppression,'
Main Steam, Extradion Steam, Auxilary Steem, Turbine and Support
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systems, l.ube Oil, Weste Management, Wolor Treatment Plant, Chemical j
and Volume Control, Sensco Water, Post Accdont Sampung, Sowege Trealment, Primary Water, Hypochlortle, Gas House, ICW, and voteaus support systems.
Licensee commenced voual inspections of electncel power systems j
integnty looking for such things as equipment which may have been j
tampered with as eWenced by switch mechanisms altered, cooling _ fan blockage, panel access altered, connecten boltmg loosened, breaker l.
raciong mechanisms altered, unauthortred grounds, foreign objects i
present, or any conchtson which could w,,,pw.!:: the integnty of the l
power system. Subsystems irimpar4=rt were: EDGs,6.gKV and 4.2KV l
switchgear, Switchyard, Main transfonnors, Auxshery transformers, Start-up i
transformers, Load Center transformers, 480V load centers and Motor U
Control Centers, Battenes and Chargers, DC load centers, Irworters, MotorGenerator Sets, and Voltage Regulators.
NRC Resident inspedor conducted visual ina-+A-tM-: = of the followng syssoms/ areas for both units: Main Control rooms, ECCS Pump rooms, Reactor An=hary buildings including the pipe tunnels and i
penetrabon rooms, Auxilary Foodwater buildings, Cable Spreadmg rooms, Turtune buildmos, EDG buikkngs, and the Outside yard. No abnormalities were identwied.
. NRC Resident inspector reviewed _w,,1C:1 Locked Valve lock check procedure, 1/2 0010123, Admmistrative Control of Valves, Locks, and i
Switches, which was used to verify locks on locked v?ives were not tampered with.
At 1:00 p.m., two NRC Region ll Physcal Security inspectors arrive onsite.
At 3:00 p.m., NRC Security inspectors toured' affected areas with FPL Corporate investigators.
At 5:23 p.m., Site Security changed to different method of checking plant areas via foot patrol.
At 5:30 p.m., the licensee terminated the patrolling functions of non-security plant personnel.
At g:30 p.m., NRC Security inspector on site to observe Site Security patrols.
1 At 10:12 p.m., NRC Security inspector and a Site Security Lieutenant observed some Security patrol deficiencies. These deficencies were subsequently discussed with Security Shift Supervisor and patrol methods j
were changed
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A-5, Attachment A
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i AUGUST 18,1996 l
Licensee &,,T; ij pipeg and valve visualinspections. No abnormaillies j
were identilled.
l The NRC Resident inspector independently performed visual inspections of l
piping and valves on both units to identify any abnormeillies associated with the following systems: HPSI, LPSI, Containment Spray, Charging Pumps, Auxilary Feedwater, CCW, Safety Reisted Switchgear, and EDGs systems..No abnormalities were identilled.
Licensee ce,T-;'ij inspection of both unit HSDPs for additional damage.
No abnormalities were identified NRC Resident inspectors performed independent voual checks of the safety 4 elated switchgear and-motor control centers to vonfy that power was available to both the breakers and charging spnng motors. Extemal inspedions were also conducted of the valve motors===am with each of the safety systems that the inspectors inspected NRC Resident inspector monitored licensee actrvities and pedormed general piant inspections paying particular attenten to secunty patrois maintaining their presence throughout the plant.
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About 2:30 a.m., Site Secunty increased the number of patrols in each unit to expand patrol coverage.
._At 1:00 p.m., licensee management goryfucted a confomnce call witti.
various NRC Region il and NRC Headquarters-Nuclear Reactor Regulaten managers and staff.
Licensee operational walk <$own of plant equipment in progress.
Site Security; continues to refine patrol duties.
FBI now in monitoring role. -
Licensee was informed that a Region ll speaal team will anive on August ig,1996.
1 About 3:00 p.m., NRC Security inspector walked down areas of concem i
with Site Security personnel.
i At 3:30 p.m., NRC Security inspector bnefed by Corporate investigators on status of investigation.
About 9:30 p.m., NRC Security inspector observed there were numerous i
Site Security patrols touring the affected areas.
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A-6, Attachment A
9 1-j AUGUST 17,1998 j
Licensee commenced detailed safety system examinations on both units.
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Technical W requirements were used as the overeN acceptance i
critoria. Examinations included performmg mejor system flowpath vesifications, operational runs of related equipment (e.g. Starting Pumps),
visual inspections, and soloded instrumentation trend reviews i
Pumps started were: HPSI, LPSI, Containment Spray, CCW, j
ICW, Auxihary Feedwater, Fire Suppression, Fuel Pool Cooling.
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EDGs were started and Reactor Protodion System Trip Circuit
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Breakers visuaNy examined.
I Major flow path venficatens (major valve position and elodrical i
Imeups) were done for: Auxiliary Foodwater, CCW, ICW, HPSI, l
LPSI, Contamment Spray, Chemical and Volume Control, Fire j
Suppression systems.
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Licenses ventied remote Normallisolate switches through out the plant to be in the Normal position.
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4 Licensee verified Thermal Overload Bypass switches through out the plant j
to to in the proper configuration.
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Licensee ven6ed proper operation of Emergency Lighting.
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._NRC Resident inspector witnessed valve position verifications for botit l
units on the followng systems: HPSI, Low Pressure injection, Containment j
Spray, and CCW. No abnormalities were identified.
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NRC Resident inspector reviewed w,,,- 'fz d documentshon for both units i
for operational pump runs performed by the licensee for HPSI, LPSI, and l
Containment Spray systems No abnormalities were identified.
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NRC Security inspector observed patrol routes. NRC inspector determoed that the Security officers had not been bnefed on the specsfic equipment that was damaged. Security manager directed all Security
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officers be bnefed on what areas were vulnerable to tampering.
3 AUGUST 18,1996 Loensee contmuod detailed safety system operational verifications. No j
abnormalities were identified.
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NRC Resident inspector continued monitonng of licensee activites.
Reviewed valve lineups, logs, and performed general plant and control room walkdowns.
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A-7, Attachment A
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i AUGUST 19,1les Licensee wT 'tj dotaded safety system operabiiity verificebons.
NRC Resident inspedor performs wansdown of identified actons unng Control Room IM Procedure 1-and 2 0030135. Key control problem identified by Resident inspector.
NRC Team Leader for Speaal inspechon Team amves on site and conducts entrance mooting with licensee management. -
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About 3:50 p.m., Site Secunty force reduced specal patrolling actrvities.
Patrol actubes contmus at an above normal level.
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AUGUST 21,1996 In response to discussions with the NRC Special inspechon Team, the hcensee mT-f_'_;j additional woualinspechons of areas in the weiruty of the unit Control Rooms looldng for any sunpidous or unauthonzed foreign j
objeds. Areas inspected were the Technical Support Center, offices, kitchen..and ventdation rooms. No abnormalibes were identi5ed.
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A4, Attachment A
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i, i
j INFORMATION PROVIDED TO UCENSEE BY NRC ON AUGUST 15,1998 (1)
NRC Information Nobce 83-27 l
1 (2)
NRC Intemal memo dated 12/12/85 i
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(3)
NRC Intemal memo dated 7/14/82 I
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i B-1, Attachment B I