IR 05000387/1985028
| ML20206M832 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 06/25/1986 |
| From: | Starostecki R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | Holahan G Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20206M839 | List:
|
| References | |
| NUDOCS 8607010299 | |
| Download: ML20206M832 (3) | |
Text
{{#Wiki_filter:,
JUN 2 51986 MEMORANDUM FOR: G. Holahan, Director Operating P,cactors Assessment Staff, NRR FROM: Richard W. Starostecki, Director Division of Reactor Projects, Region I SUBJECT: INSTRUMENT CHANNEL FUNCTION TESTING As a result of an inspection conducted on August 26 - September 29, 1985 at the Susquehanna Steam Electric Station a notice of viola ion was issued. The vio-lation identified a failure to test the entire HPCI isolation and actuation channels during functional testing. Enclosed is the combined inspection report which contains the violatio (50-387/85-28; 50-388/85-23, Enclosure I).
Region I, in a letter dated March 5,1986 (Enclosure II) requested more infor- , mation than was presented in a PP&L response letter dated November 15, 1985 (Enclosure III), and on March 14, 1986 a management meeting was held. During the meeting it was proposed that PP&L provide a submittal describing their channel functional testing program for NRC review. Mr. Srinivasan from your staff was at the meeting and indicated that NRR would review such a submittal to determine the adequacy of the PP&L program. The enclosed PP&L letter dated April 22, 1986 (Enclosure IV) is PP&L's submittal describing their channel functional test program. I am providing you with the enclosed detailed informa-tion and, in accordance with the agreement made at the March 14 meeting, request that your staff review this information and provide Region I with an evaluatio We can then determine the proper course of action. A proposed Task Interface Agreement is provide Please provide a timely response to this request in order to resolve this matter as soon as possibl Your assistance is greatly appreciate OrigtnaL Glecod Eys Richard W. Starostecki, Director Division of Reactor Projects cc: R. Bernero, BWDO, NRR M. Srinivasan, BWEI, NRR G. Lainus, BWAR, NRR W. Kane 86070102998606gB7 H. Kister PDR ADOCK 0500 J. Strosnider G L. Plisco R. Fuhrmeister
*RI:DRP *RI:DRP I:DRP Peleschak Strosnider Kister S arostecki 5/ /86 6/ /86 6M /86 6[[ 86 *SEE PREVIOUS CONCURRENCE PAGE n h
*
'
,_
.
4.\ MEMORANDUM F0R: Ro . Bernero, Director Divisi ling Water Reactor Licensing, NRR FROM: Richard W. Starostecki, Director Division of Reactor Projects, Region I SUBJECT: INSTRUMENT CHANNEL FUNCTION TESTING
As a result of an inspection conducted on August 26 - September 29, 1985 at the Susquehanna Steam Electric Station a notice of violation was issued. The violation identified a failure to test the entire HPCI isolation and actuation channels during functional testin Enclosed is the combined inspection report noting this violation.50-387/85-28; 50-388/85-23 (Enclosure I).
. Region I, in a letter dated March 5,1986 (Enclosure II) requested more infor-mation than was presented in a PP&L response letter dated November 15, 1985 :
(Enclosure III), and on March 14, 1986 an enforcement conference was hel During the meeting it was proposed that PP&L provide a submittal describing ,
' their channel functional testing program for NRC review. Mr. Srinivasan from '
, '
your staff was at the meeting and indicated that NRR would review such a sub-mittal to determine the adequacy of the PP&L program. The enclosed PP&L letter
'
dated April 22,1986 (Enclosure IV) is PP&L's submittal describing their channel function test program. I am providing you with the enclosed detailed informa-tion and, in accordance with the agreement made at the March 14 meeting, request
that your staff review this information and provide Region I with an evaluatio We can then determine the proper course of action. A proposed Task Interface Agreement is provide Please provide a timely response to this request in order to resolve this matter as soon as possible. Your assistance is greatly appreciated, i Richard W. Starostecki, Director Division of Reactor Projects cc: W. Kane
- H. Kister J. Strosnider
' M. Srinivasan G. Lainus R. Jacobs L. Pilsco R. Fuhrm ster R RI:DRP RI:DRP RI:0RP
~
hak Strosnider Kister Starostecki f86 b/ / /86 5/ /86 5/ /86 0FFICIAL RECORD COPY 290STROSNIDER5/29/86 - 0001. /29/86
,
r Task Interface Agreement Task N Date: TAC N Problem: Channel Functional Testing Lead Office: IE X NRR Region Joint Notification: Letter dated April 22, 1986 References: Meeting with PP&L Management March 14, 1986 Action Plan: NRR: Review and provide Region I with an evaluation of the enclosed letter regarding the Channel Functional Tests at Susquehanna SE Region I: Provide backup support and clarification, as requeste Office Coordinator: R. Starostecki (Ext. 5229) or H. Kister (Ext. 5233).
Approved: IE Region I R. Bernero, NRR (Ext. 8529) cc: V. Stello, EDO G. Holahan, NRR D. Eisenhut, NRR J. Taylor, IE C. Heltemes, AE00 H. Denton, NRR G. Lainas, NRR R. Wessman, NRR E. Jordan, IE T. Speis, NRR E. Adensam D. Wagner, NRR
'^
r
* ~ . ( ( . .
Enc \asure /
. .
.
OCT 1 Y 1985 Docket Nos. 50-387 50-388 Pennsylvania Power & Light Company ATTN: Mr. H. W. Keiser Vice President Nuclear Operations 2 North Ninth Street Allentown, Pennsylvania 18101 Gentlemen: 2: Subject: Routine Resident Inspection 50-387/85-28; 50-388/85-23 (8/26/85 - * 9/29/85) This routine inspection of the Susquehanna Steam Electric Station covered plant operations, surveillance, maintenance, ESF system walkdowns, open items, and licensee events. The inspection focused on reviewing the technical adequacy of surveillance testing on the reactor protection system (RPS), High Pressure Coolant Injection (HPCI) system, and containment isolation excess flow check valves. The inspector identified one violation in which HPCI monthly channel functional tests do not test the entire channel as required by Technical Specifications: Please reply to this matter in accordance with Appendix This letter also acknowledges your September 13, 1985 reply to the Notice of Violation forwarded by NRC Region I letter dated August 16, 1985. The corrective actions described in your reply will be evaluated during routi NRC Inspectio Your cooperation with us is appreciate .
Sincerely, . Origincl : y: Harry B. Kister, Chief Project Branch No. 1 Division of Reactor Projects
Enclosures:
Appendix A, Notice of Violation Combined NRC Inspection Report 50-387/85-28; 50-388/85-23 0FFICIAL RECORD COPY CIR SUS 85-28/23 10/10/85 ;
. . . - - ^^ % p, T ,
o ery.n.ayp i a f - -
-
j
. _ . _ . . .. ._ . _ ._ , . . ( (
Pennsylvania Power & Light Company 2
.
REGION I== Report No /85-28; 50-388/85-23 Docket No (CAT C); 50-388 (CAT C) License No NPF-14; NPF-22 Licensee: Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Facility Name: Susquehanna Steam Electric Station Inspection At: Salem Township, Pennsylvania Inspection Conducted: August 26, 1985 - September 29, 1985 Inspectors: ' Z(Sch / bht /pf R Jacobs, Senior Resident Inspector date
); c $ 9 :
c yL
:
Plisco, Resident Inspector Ah/fr date Approved By: c "9 _ A//v//T
/Re/Strosnider, Chief date actor Projects Section 18, DRP Inspection Summary: . Areas Inspected:
Routine resident inspection (U1 - 129 hours; U2 - 121 hours) of plant operations, licensee events, open items, surveillance, maintenance, ESF system walkdown and TMI action plan item Results: Response to SIL 402 concerning N2 inerting and makeup is satisfactory (Detail 1.8); ESF walkdowns of containment isolation and ESW systems identified minor FSAR and procedure deficiencies (Detail 2.3); review of RPS surveillances identified concerns that RPS bypass logic is not tested and other discrepancies (Detail 5.2).
One violation was identified concerning not testing the entire channel on HPCI Channel Functional Tests (Detail 5.2).
-~r w'-
. . . . - .
kf
. ( (
.
DETAILS 1.0 Followup on Previous Inspection Items 1.1 (Closed) Unresolved Item (387/83-21-05): Thermal Overload Bypass Circuit Design As reported in LER No. 50-387/83-129, a motor operated valve (MOV) which supplies cooling water to the HPCI turbine barometric condenser and the pump lube oil cooler was found inoperable on September 27, 1983 during a surveillance test. Investigation found the valve motor overload heaters burned open and the valve motor operator damage Valve electrical damage resulted when the torque switch did not actuate on valve closure due to conditions in the spring pack (See LER 83-140). The condition was not indicated or annunciated to the control room operator due to the circuit design. In the existing design of the MOV control circuit, a motor operated valve with a burned out motor would not be annunciated or indicated as inoperable
~
as long as the bypass circuit of the thermal overload protection was in effec In this specific occurrence, the condition went undetected for approximately three week ~ The purpose of the bypass' fe'alure around the TOL device is to avoid spurious trips of MOVs under accident demand situations. One of the regulatory positions stated in Regulatory Guide 1.106 is that the TOL should not preclude completion of the safety function. Continuous bypass of the TOL during normal operation, as it is done at Susquehanna, is one means of complying with Regulatory Guide 1.10 It is also good engineering practice to retain the TOL protection for the normal or test functions of the MOV. Such a design permits the bypass to be removed to reinstate the TOL protection for the motor under test conditions. The Susquehanna design also meets this objective by use of a manual switc NRR review of the circuit design following this event found it to be acceptable. NRR stated that the periodic testing of the MOVs
.
required by Technical Specifications is adequate to identify and _ rectify any defects / failures which might have occurred since the last test. The periodic test interval for critical components is chosen such that any failures that occur between tests do not pose undue
-
risk to the plant and safety of the publi An engineering evaluation of the thermal overload bypass circuit performed by the licensee also concluded that the circuit meets the intent of Regulatory Guide 1.106 and no design modifications were required. The operating procedures have been revised to require the MOV test switches to remain in the test position for at least two minutes following a valve closing operation to assure proper indication if the overload relays actuate. Effective implementation
.
( (
.
of the procedural requirements should prevent recurrence of this type of undetected failur LER 387/83-129, dated October 21, 1983 stated that the LER would be updated, but an update has not yet been submitted to the NRC to summarize the completed corrective actions. The inspector discussed this with the licensee who stated that an LER update would be submitted in the near futur .2 (Closed) Violation (387/83-23-02): Changes Made to the Primary Containment Isolation Actuation Logic Prior to Issuance of Operating License NPF-14 On October 7, 1983, the licensee reported that a review of Technical Specifications uncovered discrepancies concerning initiating signals for ten containment isolation valves. (See LER 83-130). The discrepancies were caused by the failure to make the proper FSAR and Technical Specification changes after the design was revised by General Electric. Further licensee review identified an additional eleven discrepancie The licensee has now assumed total responsibility for the design change process which eliminates reliance on Bechtel and General Electric for initiating FSAR updates due to future design changer The licensee has reviewed its own program for processing FSAR charge requests associated with plant modifications to ensure subsequent annual FSAR updates adequately reflect the plant desig The licensee reviewed the FSAR discrepancies identified and submitted corrections in the July 1984 annual FSAR update. The Technical Specifications were also corrected. The inspector reviewed the FSAR, Technical Specifications, and electrical schematics and verified that the discrepancies identified in LER 83-1,30 had been correcte .3 (0 pen) Deviation (387/85-16-03): No Control Room Indication for Unbypassing Thermal Overloads * In April 1985, the inspector identified that .the thermal overloads on forty-five safety-related motor operated v'alves in the ESW and RHRSW systems can be unbypassed by test switches on Panel OC697 in the control room, but the unbypassing of these overloads is not indicated in the control room. This condition is contrary to FSAR Section 7.3.1 for the ESW inlet and outlet valves to the diesel generators and appeared to be contrary to Regulatory Guide (RG) 1.106 Revision 1, to which the licensee is committed. R.G. 1.106 states that the indication circuitry should conform to Section 4.13 of IEEE 279-197 This section states that "if the protective action of some part of the system has been bypassed or deliberately rendered inoperable for any purpose, this condition shall be continuously indicated in the control room". Region I considered the protective action referred to above to be the unbypassing of the thermal overloads since they are
.
( (
.
required by the Technical Specifications to be continuously bypassed on safety-related motor operated valves. Region I issued a Notice of Deviation against the FSAR and R.G. 1.106 for this conditio In the deviation response dated July 16, 1985, the licensee acknowledged the deviation from FSAR Section 7.3.1, but took exception to the deviation from R.G. 1.106. The licensee's interpretation of Section 4.13 of IEEE 279-1971, as it applies to R.G. 1.106, is that " protective action" means the protective action or function of the affected valve. With the thermal overloads unbypassed, the function of the affected valve could still be completed through the overloads. The inspector requested that NRR (Power Systems Branch) review this deviation response. NRR indicated that, while it is desirable to provide indication of the bypassed condition, it is not specifically required by NRR's interpretation of R.G. 1.10 Therefore, the licensee is not in deviation with .10 The licensee indicated that the statement in FSAR 7.3.1 concerning providing indication of the unbypassing of the thermal overloads for the ESW inlet and outlet diesel generator cooler valves, was in error. This statement will be corrected with the next annual update of the FSAR in July, 1986. This deviation will remain open until the
~~
FSAR i s correcte .4 (Closed) Unresolved Item (387/84-07-06; 388/84-08-04): Deficiencies in Containment Isolation Dependability During a review of TMI Action Item II.E.4.2, Containment Isolation Dependability, the inspector identified deficiencies in the FSAR, Technical Specifications, and system drawings. Four of the deficiencies have been corrected by FSAR revisions and drawing changes and were verified by the inspecto Two of the deficiencies remain open and require Technical Specification changes. These deficiencies involve penetrations X-211, X-216, and X-218. The licensee has conducted an extensive review to ensure all of the documents concerning containment isolation are consistent and, as discussed in Detail 2.3 of this report, are actively pursuing correction of the items. The remaining two open deficiences will be tracked under item 50-387/85-28-0 .5 (Closed) Violation (387/84-35-02): Average Scram Insertion Time for Four Rod Array did not meet Technical Specification Requirements and was not Noted During the Surveillance On June 25, 1984, when Surveillance Procedure SR-155-003 was performed using scram insertion time data from a June 13, 1984 scra The average scram insertion time to notch position 45 for the three fastest rods in a four rod array did not meet the Technical Specification acceptance criteria. The slow scram insertion time was _
__
. . ( (
.
I not detected due to inadequate review of the completed surveillanc This violation was discussed during an Enforcement Conference at NRC Region I on November 30, 1984. This event demonstrated the need for more thorough review of completed tests to assure problems are identified in a timely manner and satisfactorily resolved. The cause of the scram pilot solenoid valve failures was previously discussed in Inspection Report 387/85-0 The licensee provided their response to the violation on February 14, 1985 (PLA-2400). The response discussed the corrective action taken and an on going independent review of the surveillance program implementation. The corrective actions included the following:
--
The scram insertion time computer program was modified to specify all Technical Specification acceptance criteria on page one of the computer printou Reactor Engineering personnel attended training concerning the incident and to review each engineer's responsibilities during performance of surveillance Reactor Engineering surveillances were reviewed and revised as necessary to include an "As Found" column for each acceptance criteri The inspector verified completion of the corrective actions noted in the violation response and reviewed several surveillances performed l subsequently, with no findings note .6 (Closed) Unresolved Item (387/85-11-05; 388/85-11-05): Apparent Failure to Verify Each Valve in the LPCI Flow Path Was in its Correct Position In February 1985, the inspector noted that the licensee used control room position indicating lights instead of local valve position indication to satisfy the surveillance requirements of Technical Specification (TS) 4.5.1. This, Technical Specification requires periodic ve,rification that certain valves in the emergency core cooling system flow path are in their correct position. The inspector questioned whether remote position indication met the intent of the surveillance requiremen Discussions with NRR found that the intent'of the surveillance requirement is to assure that valves in the flow path for the emergency core cooling systems are in their correct position such that the system would not be rendered inoperable due to a mispositioned valve. Additionally, for valves which have remote position indicating lights in the control room, the remote position indication may be used to verify that valves are in the correct positio It is the.refore not the intent of the Technical Specifications to have only local valve position indication utilize . . . _
( (
.
The Inservice Inspection requirements of Section XI of the ASME Boiler and Pressure Vessel Code require that valve position indications be observed at least once every 2 years. Experience has shown that the low frequency of incorrect valve position indication events justifies use of the remote indicating light.
1.7 (Closed) Inspector Followup Item (387/85-11-01; 388/85-11-01): Failure to Include a Walkdown of Inner Ring Panels on the Shift Turnover Checklist The inspector identified that the shift turnover checklist used by the plant control operator (PCO) did not include a walkdown of inner ring panels to assure the availability and proper alignment of all systems essential to preventing and mitigating operational transients and accident The walkdowns were actually performed during the two shift turnovers observe Administrative Procedure, AD-QA-303, Shif t Routine has been revised to include the panel walkdown on the PCO checklist, and was reviewed by the inspector.
1.8 (Closed) (387 and 388/TI-2500-12): Licensee's Response to SIL 402, Nitrogen Inerting (Open) Unresolved Item (387/85-12-04): Nitrogen Inerting - SIL 402 In accordance with IE Temporary Instruction 2500-12, in May 1985, the inspector reviewed the licensee's response to GE Service Information Letter (SIL) 402, Followup-Wetwell/Drywell Inerting. The inspector found that the licensee's response dated September 24, 1984 contained a number of discrepancies. In response to the inspector's findings, the licensee supplemented their response by letter cated May 1,198 The licensee reevaluated the design of the nitrogen inerting and makeup systems for the potential for injecting cold nitrogen into containmen Inerting and Makeup Design and Operation The nitrogen inerting system used a truck mounted, vendor supplied nitrogen rig using either a direct fired or ethylene glycol vaporizer. There is no permanent temperature indication on the line or low temperature shutoff valve. A local temperature gage has been mounted on the temporary flange connection used to connect the truck to the installed inerting piping. A PP&L operator monitors the temperature by procedure to ensure the gas temperature is above 80 degrees F. The nitrogen enters the containment through the 24 inch drywell and 18 inch suppression chamber purge lines. There is no distribution pipe network inside containmen . _ _ - _ _
{ (
.
The nitrogen makeup system, which is used to supply nitrogen to containment for pressure control, consists of a 1500 gallon liquid nitrogen tank, ambient vaporizer and distribution pipin The tank has a low temperature shutoff valve designed to shutoff flow if gas temperature drops below -20 degrees F. There is no pressure or temperature indication in the makeup piping. The nitrogen enters the drywell and wetwell through 1-inch penetrations and there is no pipe network inside containmen Based on the design of the systems, the licensee concluded that there was reasonable assurance that the inerting system would not inject cold nitrogen, but that normal operation of the makeup system might not prevent cold nitrogen injection. The licensee committed to install temperature indication on the makeup line and revise procedures accordingly by October 1, 198 Orientation of Inerting and Makeup System Piping The licensee inspected the Unit I drywell and reviewed Unit I wetwell and Unit 2 drywell and wetwell drawings to determine if the possibility existed for direct impingement of nitrogen on safety-related equipment. The only concern identified by the licensee was that the nitrogen makeup penetrations in the Unit 1 and 2 wetwells are approximately 1-foot away from a downcomer allowing nitrogen impingemen The licensee has performed an analysis to determine the temperature at which nitrogen would have to be injected to cause a brittle fracture concern with the downcomer pipes. The inspector reviewed the analysis (Calculation No. EA-B-Nn1063) and M-CAC-006). The injection temperature (i.e. the temperature t of nitrogen in the makeup piping) would have to be less than-250 degrees F. to reach the nil ductility temperature of -20 de5rees F. for tne SA106 GrB downcomer The non safety related makeup piping nil ductility limit is also -20 degrees F. so this becomes more limiting and the minimum operating temperature as sensed at the temperature element will be set at -5 degrees to accommodate thi In any event, impingement of cold nitrogen on the downcomer piping does not create a brittle fracture concer Verification That No Damage from Cold Nitrogen Injection Exists SIL 402 described three other activities which licensees' should perform to ensure that no damage exists from injection of cold nitrogen. These activities were 1) perform a drywell/wetwell bypass leakage test, 2) conduct ultrasonic testing of the nitrogen injection line and, 3) perform a visual inspection of components inside containment which may have been affected by cold nitrogen injection.
l l l L
(
-
(
The licensee performs drywell/wetwell bypass leakage tests per Technical Specifications (TS) requirements. The inspector verified that the latest results for both Units were satisfactor The licensee performed an inspection of the Unit 1 containment inerting and makeup penetrations in March 1984 and the Unit 1 makeup and inerting lines were hydro tested in February 198 The inspector verified that the above inspection and test were performed with satisfactory results. In addition, following an overpressurization of the inerting line in December 1984, nineteen welds in the line were UT inspected with satisfactory results. Unit 2 was inerted for the first time in January 1985 and the licensee will perform a visual inspection of Unit 2 inerting piping, valves and penetrations during the Unit 2 first refueling outag In summary, there is no evidence that cold nitrogen injection has occurred at Susquehann The only concern was the possibility of injection of cold nitrogen via the makeup system, since there is no temperature indication in the system, the low temperature shutoff valve actuates at a very low temperature (-20 degrees F.) and safety related components, i.e. , downcomer pipes, are near the injection penetrations in the wetwel The licensee has performed an analysis to show that this is not a concern. In addition, the licensee is installing temperature indication in the makeup line by October 1, 1985, This will be reviewed under unresolved item 387/85-12-0 .9 (Closed) Inspector Followup Item (387/83-06-04): Computer Reinitialization Durinc a Transient In March 1983, a recirculation pump runback occurred while the computer room was reinitializing the computer which prevented information updating on the control room displays. The control room operators were unaware that the computer technician was reinitializing the displays and a turbine trip occurred before the operators recognized that the displays were not updating and could take actions to prevent the tri By station policy, computer technicians do not reinitialize control room displays without permission of the plant control operator. In addition, per Administrative Directive, AD-QA-300, Conduct of Operations, the STA monitors the Safety Parameter Display System (SPDS) during off-normal conditions and advises the operators of any adverse trends noted. No further incidents similar to the above have been observe .0 Review of plant Operations 2.1 Operational Safety Verification The inspector toured the control room daily to verify proper manning, access control, adherence to approved procedures, and compliance with _ _ . -
.
. -
f (
.
LCO Instrumentation and recorder traces were observed and the status of control room annunciators were reviewed. Nuclear Instrument panels and other reactor protection systems panels were examined. Effluent monitors were reviewed for indications of releases. Panel indications for onsite/offsite emergency power sources were examined for automatic operability. During entry to and egress from the protected area, the inspector observed access control, security boundary integrity, search activities, escorting and badging, and availability of radiation monitoring equipmen The inspector reviewed shift supervisor, plant control operator, and nuclear plant operator logs covering the entire inspection perio Sampling reviews were made of tagging requests, night orders, the bypass log, Significant Operating Occurrence Reports (S00Rs), and QA nonconformance reports. The inspector observed several shif t turnovers during the perio .2 Station Tours The inspector toured accessible areas of the plant including the control room, relay rooms, switchgear rooms, cable spreading rooms, penetration areas, reactor and turbine buildings, security control center, diesel generator building, ESSW pumphouse, and the plant perimeter. During these tours, observations were made relative to equipment condition, fire hazards, fire protection, adherence to procedures, radiological controls and conditions, housekeeping, security, tagging of equipment, ongoing maintenance and surveillance and availability of redundant equipmen On August 23, 1985, during a tour of the Unit 2 Reactor Building (RB), the inscector identified that the door to the fuel pool pump room on the 749 foot elevation was not locked and the room was unoccupied. This room is a posted High Radiation area, and is required to be locked in accordance with station policy (Acministrative Directive AD-00-705, Access Control and Radiation Work Permit System). The RB Nuclear Plant Operators (NP0s) routinely enter this room to take readings and to fill the fuel pool skimmer surge tan The door was apparently lef t unlocked by a RB NP The inspector notified Health Physics personnel who immediately locked the door. At the request of the inspector, the licensee performed a survey of the room. The highest general area readings in the room were 80 mrem / hour which is-less than the 100 mrem / hour - requirement for a High Radiation area. Technical Specification (TS) 6.12 only requires locking doors to areas with general area dose rates greater then 1000 mrem / hour. Hence, this room is not required to be locked by T Even though dose rates in this room were relatively low, the concern of not strictly following Health Physics requirements still exist The inspector discussed this concern with the Station Superintendent _ ,__ _ _ _. . _
..
- -
_ _ -
, . . . ( (-
and Operations Supervisor. All operations Shift Supervisors were directed to reinforce High Radiation door requirements with their shift .3 ESF Walkdown 2. Containment Isolation System The inspector conducted a review of the system design, operability requirements and operating procedures concerning the Unit I and Unit 2 Primary Containment Isolation System. The comprehensive review included the following:
--
Confirmation that the system check-of f lists and operating procedures are consistent with the plant drawings and as-built configuration,
--
Identification of equipment conditions and items that might degrade performance, Verification that accessible system valves, breakers,
--
and switches are properly aligned, and appropriate valves are locked,
--
Confirmation that the FSAR, Technical Specifications, and plant drawings are consistent concerning penetration configurations and isolation actuation signals,
--
Verification that the containment penetrations and associated isolation valves are adequately tested in accordance with Technical Specification surveillance requirement The following references were util.ized during this review:
--
Technical Specification 3.3.2 and 3. ON-259-002, Revision 3, Containment Isolation
--
FSAR Tables 6.2-12 and 6.2-22
--
GE Elementary M1-821-101, Nuclear Steam Supply Shutoff System
--
P&ID M-2157, Containment Atmosphere Control
--
P&IO M-2126, Containment Instrument Gas
.- .. -, -- _ - _--_ - . . - .
. ____ - ( (
.
The following items were identified during the review:
(a) Technical Specification Table 3.6.3-1 and FSAR Table 6.2-12 are inconsistent concerning containment penetration X-218 for Containment Instrument Gas. The FSAR describes the line being isolated by automatic isolation solenoid valve SV-12671 and simple check valve 1-26-164. A note associated with this penetration states that an exemption is ree. fred for a check valve outside containment (General D sign Criteria 56 states that a simple check valve may not be used as an automatic isolation valve outside containment). Another check valve, 1-26-070, is in the same process line inside containment. Unit 2 Technical Specifications lists both check valves as primary containment isolation valves. Unit 1 Technical Specifications lists only the inboard check valve, 1-26-07 Both valves are tested during the penetration local leak rate tests, SE-159-090 and SE-259-090. The FSAR and/or Technical Specifications require revision to specify the correct penetration configuratio (b) FSAR Table 6.2-12 lists check valves E41-1F046 and E51-1F021 as isolations for penetrations X-211 and X-216 respectively. The FSAR also notes that the two check valves require an exemption for a check valve outside containmen The penetrations are used for the HPCI and RCIC minimum recirculation flow lines. Technical Specification Table 3.6.3-1 does not include these two valves as primary containment isolation valves as require The valves are tested in the penetration local leak rate test procedures, SE-159-085 and SE-159-08 According to section 6.2.4.3.3.2 of the FSAR, the justification for the alternate approach taken for isolating these lines is that the check valves, with the water seal provided by the suppression pool and the external piping acting as a second barrier, provide leakage control in the short term. The Technical Specifications Table requires revision to be consistent with the as-built configuratio (c) Unit 1 Technical Specification Table 3.6.3-1 lists manual isolation valves 1-57-193 and 1-57-195 for isolation of ILRT testing penetration X-61 According to system drawings and plant procedures the correct valves for this penetration appear to be i
.
l _,, - - ,.
- ' ( (
.
1-57-193 and 1-57-19 This appears to be a typographical error in the Technical Specificatio Valve 1-57-195 is actually a normally open instrument line isolation. The Technical Specification Table requires revision to be consistent with the as-built configuratio (d) During a walkdown of penetration installations the inspector noted that an incorrect identification tag was attached to solenoid valve SV-2267 The nametag was for manual isolation valve 2-26-071, which is inside containment. The inspector informed the licensee who removed the incorrect ta Licensee corrective actions for the deficiencies noted above will be reviewed in a subsequent inspectio (387/85-28-01) The deficiencies noted in (a) and (b) were previously identified in open items 387/84-07-06; 388/84-08-04 As , stated in Detail 1.4, the open items will be closed and deficiencies (a) and (b) tracked under the new open ite . Emercency Service Water On September 18, 1985, the inspector independently verified the operability of portions of the Emergency Service Water System by performing a walkdown of the accessible portions of the system. The engineered safety feature system status verification included the following: Confirmation that the system check-off list and
--
operating procedure are consistent with the plant drawings and as-built configuration, Identification of equipment conditions and items that
--
might degrade performance, Inspection of breaker and instrumentation cabinet
--
interiors,
--
Verification that the surveillance procedures
-
adequately implement the Technical Specification surveillance requirements,
--
Verification of properly valved in and functioning instrumentation,
--
Verification that system valves, breakers, and switches are properly aligned, and appropriate valves are locked.
! '
~
- ( (
The following references were utilized during this review:
--
OP-054-001, Revision 4, Emergency Service Water System (ESW)
--
P&ID M-111, Emergency Service Water System
--
Technical Specification 3.7. S0-054-001, Revision 2, Emergency Service Water System Monthly Alignment Check The following items were identified during the review: Two valves shown on the ESW drawing were not included
--
on the valve check off list (COL) in operating procedure OP-054-001. Manual isolation valves 0-11-23A and 0-11-23B are 10 inch valves which were installed during the tie-in outage to provide the ESW source to the fifth diesel. The valves were
. tack welded closed and buried until tie-in of the fifth diesel. Due to their inaccessibility the valves were not included in the CO .
The inspector-had no further question In Attachment D to OP-054-001, Motor Operated Valves
--
HV-11143A and HV-1143B were incorrectly identified as manual valves 11143A and 111438. In addition, the motor-operated valves are not correctly identified in 50-054-001. The licensee initiated corrective action to revise the procedure CO The inspector determined that the system was properly aligned in accordance with the operating procedure and plant drawing .4 Semi-Annual Health Physics Drill
-
On August 27 and September 24, 1985, the licensee conducted emergency planning drills, exercising Technical Support Center (TSC) and Emergency Operations Facility (EOF) personne The inspector observed portions of the drills from the simulated Control Room and the TSC. The drills appeared to be well controlled. The inspector noted one concern, however, during the September 24 drill where the Public Information Manager at the Media Operations Center called the control room five times in forty-five minutes. The plant was not in a stable condition and these distractions were, in part, responsible for the control room not making required notifications within fifteen minutes for the upgrade to a Site Emergenc This concern was noted by one of the referees and the inspector discussed it with the lead referee and the plant superintendent who indicated that it would be _ _ _ _
.
(' (
.
noted at the drill critiqu No other unacceptable conditions were note .0 Summary of Operatir- Events 3.1 Unit 1 Unit 1 operated at or near 100 percent for most of the inspection perio Scheduled power reductions were conducted throughout the period for control rod pattern adjustments and surveillance testin The unit reached 100 days of continous operation on September 20, 198 .2 Unit 2 Unit 2 operated at or near 100 percent for most of the inspection perio Scheduled power reductions were conducted throughout the period for control rod pattern adjustments and surveillance testin .0 Licensee Reports In-Office Review of Licensee Event Reports The inspector reviewed LERs submitted to the NRC:RI office to verify
,
that details of the event were clearly reported, including the accuracy of description of the cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted onsite followup. The following LERs were reviewed: Unit 1 85-027-00, Offgas Pretreatrent Radiation Monitor Surveillance Not Met
~
*85-028-00, HPCI Inboard Steam Supply Valve Isolation Unit 2
**85-023-00, Reactor Scram Due to Feedwater Surveillance Error 85-024-00, ESF Actuation (RWCU Isolation on High System Flow)
* Discussed in Detail **Previously discussed in Inspection Report 50-387/85-26; 50-388/85-21 4.2 Onsite Followup of Licensee Event Reports For those LERs selected for onsite followup (denoted by asterisks in Detail 4.1), the inspector verified that the reporting requirements l
, - . - - -
.
(~ (
of 10 CFR 50.73 had been met, that appropriate corrective action had been taken, that the event was reviewed by licensee, and that continued operation of the facility was conducted in accordance with Technical Specification limit The following findings relate to the LERs reviewed on site: 4. LER 85-028: HPCI Inboard Steam Supply Valve Isolation (Unit 1) On August 23, 1985 at 9:51 a.m. the High Pressure Coolant Injection (HPCI) System was declared inoperable when the HPCI inboard steam supply valve isolated due to an Instrumentation and Control (I&C) technician error. An I&C technician performing a quarterly calibration of a pressure switch inadvertently connected his test equipment to the
. wrong terminal points which caused the valve to isolat The surveillance procedure correctly identified the terminal point The valve was reopened and the HPCI system declared operable at 10:50 a. While attempting to restore the -
system, the HPCI steam line warmup isolation valve indicated intermediate when a close signal was give After another unsuccessful attempt, the inboard steam supply valve was reclosed and HPCI declared inoperable at 2:25 p m. The HPCI steamline was depressurized and the full closed indication was received on the warmup isolation valve. The steamline did not repressurize, demonstrating the warmup valve'~was actually close Since the warmup isolation valve is a primary containment
-
isolation, an LCO was entered at 10:50 a.m. in accordance with Technical Specification 3.6.3. Based on receiving the closed indication and verifying that it was closed by ensuring the steam line did not repressurize, the warmup isolation valve was deactivated and the LCO cleared at 2:40 The inboard steam supply valve was reopened and HPCI declared operable at 7:35 p.m. the same da The limit - switch will be repaired during a future outag To prevent recurrence of the I&C technician error, the technician was counseled and procedural compliance is to be discussed at the next I&C Department monthly meetin .3 Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee were reviewed by the inspector. The reports were reviewed to determine that the report included the required information; that test results and/or supporting information were consistent with design predictions and performance specifications; that planned corrective action was adequate for resolution of identified problems, _ _
. ( 16 ( .
and whether any information in the report should be classified as an abnormal occurrenc The following periodic and special reports were reviewed:
--
Monthly Operating Report - August 1985, dated September 11, 1985 The above report was found acceptabl .0 Surveillance and Maintenance Activities 5.1 Surveillance Activities The inspector observed the performance of surveillance tests to determine that: the surveillance test procedure conformed to technical specification requirements; administrative approvals and tagouts were obtained before initiating the test; testing was accomplished by qualified personnel in accordance with an approved surveillance procedure; test instrumentation was calibrated; limiting conditions for operations were met; test data was accurate and complete; removal and restoration of the affected components was properly accomplished; test results met Technical Specification and procedural requirements; deficiencies noted were reviewed and appropriately resolved; and the surveillance was completed at the required frequenc These observations included:
-- ~
SI-178-325, Quarterly Channel Calibration of Rod Block Monitor
--
Channels A and B, performed on September 5, 1985 50-150-002, Monthly Flow Verification of RCIC System, performed on September 6, 1985
--
51-279-201, Monthly Channel Functional Test of Main Steam Line Radiation Monitors D12-603A, B, C, D, performed on September 6, 1985
--
50-252-002, Quarterly HPCI Flow Verification, performed on September 10, 1985 No unacceptable conditions were identifie .2 Surveillance Procedure Review 5. Excess Flow Check Valves The inspector conducted a review of the periodic testing requirements for the instrument lines penetrating the primary reactor containment. The review consisted of a I comparison between the FSAR, Technical Specifications, i _ __ -
' .
C C .
.
Inservice Inspection Testing program, and the as-built drawings to verify that all the associated excess flow check valves are adequately tested and the instrument lines meet the guidelines of Regulatory Guide 1.11. The following documents were reviewed:
--
FSAR Table 6.2-12a, Data on Instrument Lines Penetrating Containment
--
Regulatory Guide 1.11, Instrument Lines Penetrating Primary Reactor Containment (March 10,1971)
--
Technical Specification Table 3.6.3-1, Primary Containment Isolation Valves
--
Unit 2 Pump and Valve Inservice Inspection Testing Program
--
FSAR Table 6.2-11, Leakage Rate Test List
--
Plant Engineering Procedure PE-100-003, Revision 2, Integrated Leakage Rate Test Valve Lineup
--
FSAR Section 6.2.4.3.5, Evaluation Against Regulatory Guide 1.11
--
51-299-206, Revision 0, 18 Month Functional Test of Excess Flow Check Valves (Reactor Recirc and Core Spray)
. --
SI-299-207, Revision 0, 18 Month Functional Test of Excess Flow Check Valves (MSIV LCS, RWCU and Jet Pumps)
--
SI-299-208, Revision 1, 18 Month Functional Test of Excess Flow Check Valves (RHR/ Shutdown Cig. Perm. , HPCI and RCIC Isolation)
--
SI-299-209, Revision 0, 18 Month Functional Test of Excess Flow Check Valves (MSIV High Flow Isolation)
--
SI-299-210, Revision 0, 18 Month Functional Test of Excess Flow Check Valves (PAM, ECCS, NSSS, and RPS J Trip)
' --
SI-299-211, Revision 0, 18 Month Functional Test of Excess Flow Check Valves (XV-E11-25109A and XV-E11-25109B) i -- AD-QA-423, Revision 3, Station Inservice Inspection Prog r.am l ,
,m - , , , - . - . ,
( (
* . --
SE-159-043, Revision 0, local Leak Rate Testing of Mini Purge to Recirc Pumps Penetration Number X-31B The licensee-has stated in the FSAR that the design of the instrument lines penetrating the primary reactor containment compiies with the provisions of Regulatory Guide 1.11. Instrument lines which connect to the reactor coolant pressure boundary are equipped with a restricting orifice located inside the drywell and with a manual isolation valve and an excess flow check valve located outside containment. The excess flow check valves for these lines are tested at least once per 18 months in accordance with Technical Specification 4.6. The testing consists of opening a test drain valve downstream of the excess flow check valve and verifying proper operatio Instrument lines that do not connect to the reactor coolant pressure boundary, but penetrate containment, also conform to Regulatory Guide 1.11. The lines are equipped with manual isolation valves and excess flow check valves outside containment. For testing purposes, the instrument lines for contcinment pressure monitors and suppression pool level are treated as extensions of the containmen These lines are leak tested during the Containment Integrated Leak-Rate Test (Type A) as part of the containment boundary. The excess flow check valves in these lines are not functionally tested.
- Findings:
--
All of the instrument line excess ficw check valves on lines which penetrate containment and are connected to the reactor coolant pressure boundary are periodically tested (every 18 months) in accordance with the Technical Specification All of the instrument line excess flow check valves on
--
lines which penetrate containment and are open to the containment atmosphere are tested as part of the containment boundary during the Containment Integrated Leak Rate Test. The valves are not functionally tested, but no requirement exists to functionally test the The licensee has identified that excess flow check ! valve XV-141F009 (XV-241F009 for Unit 2) is untestable due to the design of the installatio (See Unit 1 LERs 63-08 and 85-023). A Limiting Condition for Operation (LCO) has been entered for both units, and the valve has been isolated by a locked closed manual l
. -
c C
.
valve (141005) in accordance with the Technical Specification action statement. The instrument line serves the reactor vessel head seal leak detection instrumen The inspector verified the isolation of the lines and the administrative controls implemented to ensure it remains isolate ,
--
The Surveillance procedure referenced in the Pump and Valve Inservice Inspection Testing Program to meet the testing requirements for excess flow check valves is no longer valid. The IST reference needs to be correcte Excess Flow Check Valves XV-1431F017A and B are not included in the excess flow check valve Technical Specification Surveillance requirement since they are , not considered instrument lines, but are periodically tested (every 24 months) in accordance with LLRT and IST requirements. Inspector review of AD-QA-423 found that the incorrect surveillance procedure, SI-199-205, was listed as meeting the IST requirement for these '
-
valves. This procedure originally included the functional testing requirements for the valves, but it was superceded by six separate procedures, and these valves were not included in the new procedure Additionally, acceptance criteria for the functional test and operation of the control room indications were not included in the procedure. The licensee revised the local leak rate surveillance procedure to include the IST requirement FSAR Tables 6.2-12a and 6.2-22 list an instrument line for a suppression pool pressure detector utilizing penetration X-223 The penetration is actually a spare and is not shown on the applicable drawing Inspector walkdown of containment verified that the penetration is a spare with no instrument lines attached. The FSAR tables should be revised to correctly reflect the as-built conditio Several instrument lines that penetrate containment are not properly listed in FSAR Table 6.2-12 Examples include excess flow check valves XV-1F071B-0, XV-1F0728-D, XV-1F0738-D, XV-1F0708-0, XV-15709A and B, and XV-15728A and B. The FSAR table should be revised to include all the instrument lines which penetrate containmen The manual isolation valve numbers for penetrations X-03B and X-32A are not correct in FSAR Table 6.2-12 The valve numbers do not correspond to the valves
;
_ _ _ _ - , ._. .
( C
.
denoted on the system drawings. Additionally, the associated excess flow check valves are not listed with the correct penetration (i.e. X-038 and X-32A are reversed). The FSAR table should be revised to correctly reflect the as-built conditio The inspector will review the FSAR and procedure revisions in a subsequent inspection. (387/85-28-02) 5. Reactor Protection System Surveillance Review The inspector conducted a detailed review of the surveillance procedures used to meet the surveillance requirements for the reactor protection system (RPS) on Unit 2. The review focused on verifying that the procedures were technically adequate based on RPS schematics to meet the associated channel functional and logic system functional surveillance requirement The following documents were reviewed:
--
GE Elementary Diagram for the Unit 2 RPS - M1-C72-5 Sheets 1-18
--
Unit 2 Technical Specification / Surveillance Procedure Cross Reference Matrix, Revision 1 Surveillance Procedures:
--
SI-278-201, Weekly Functional Test of Intermediate Range Monitor Channels A-N, Rev. 2 SI-278-319, Semi Annual Calibration of APRM Channels A-F, Rev. 2 SI-278-402, 18 Month Time Response Test of APRM Channels A-F, Rev. 4 SI-279-201, Monthly Channel Functional Test of Main Steam Line Radiation Monitors, D12-K603A, B, C, D, Rev. 2 SI-258-201, Monthly Channel Functional Test of Drywell Pressure - High Channels PSH-C72--N002A, 28, 2C, 20, Rev. 1 SI-258-203, Monthly Functional Test of Reactor Vessel Steam Dome Pressure Channels PS-B21-N023A-D, Rev. 1 SI-258-302, 18 Month Calibration of Scram Discharge Volume High Water Level Channel LSH-C12-N013A, B, C, 0, Rev. 1 i ( .
- -
- - . . .
.
SI-258-304, 18 Month Calibration of Scram Discharge Volume (SDV) High Water Level Channels LIS-C12-N601A, B, C, D, Rev. O SI-280-205, Monthly Channel Functional Test of Reactor Vessel Level Channels LIS-B21-N024A, B, C, D, Rev. 1 SI-280-305, 18 Month Calibration of Reactor Vessel Level Channels LIS-821-N024A, B, C, D, Rev. 1 SI-283-314, 18 Month Calibration of Turbine Control Valve Fast Closure, Trip Oil Pressure Low Channels PSL-C72-N005A-D, Rev. 1 51-283-325, 18 Month Calibration of Main Steam Line Isolation Valve RPS Limit Switches, Re O SI-283-413, 18 Month Time Response Test of RPS and E0C/RPT Trips for Turbine Stop Valve and Turbine Control Valve Fast Closure, Re , 18 Month Logic System Functional Test (LSFT) of RPS: Turbine Stop Valve Closure, Rev. 1 50-258-001, Monthly Manual Scram Control Switch Functional Check, Rev. O S0-258-002, 18 Month Reactor Mode Switch Shutdown Position Functional Check, Rev. 2 S0-293-001, Weekly Turbine Overspeed Protection System Valve Cycle Test, Rev. 1
PLIS 13,301, PP&L memorandum dated December 15, 1983,
" Surveillance Program Task Force - -
Position Papers" PLIS 13,997, PP&L Memorandum dated January 30, 1984,
" Philosophical Issues Position Papers" Discussion:
In 1983, as a result of concerns identified by the Nuclear Safety Assessment Group (NSAG) and NRC, PP&L organized a Surveillance Task Force and Procedure Review Group to address the various concerns. One objective of the Task i
!
Force was to evaluate various philosophical questions 1
_ -
. . (l (
1
.
concerning the surveillance test program and propose a PP&L position on these questions. These questions involved such , subjects as what constitutes a Channel Functional Test
- (CFT), whether CFTs are required to verify actuation setpoints, what must be tested in a Logic System Functional Test, whether RPS bypasses must be tested, etc. The positions are well described and documented. Management approved the positions in PP&L memo PLIS 13997 dated January 30, 198 Except as noted in the findings, the inspector did not take exception to the pP&L positions presented in PLIS 1399 i The findings identify discrepancies in the implementation I of these positions or the inspector's understanding of the Technical Specification requiremen Findings:
During the review, the inspector identified the following Concerns: The Logic System Functional Tests (LSFT) do not check all contacts in the RPS trip system logic. The trip system logic consists of many relay contacts in series which open to deenergize the C72-K-14 relays to cause the trip system to trip (See attached figure 1). Each relay has two redundant contacts in the logic strin For example, the C72-K4A relay (which actuates on high drywell pressure) uses contacts 1-2 and 3-4 in the
- <
logic string. Opening either contact will trip the
! trip system. The licensee's method of testing high drywell pressure for a LSFT is the same as the channel functional test, i.e. injection of a simulated signal into the detector until a one half scram occurs (K14A and E relays deenergize). This method of testing only i
verifies that one or the other contact opens, but does not verify that both contacts open. T.S. 1.21 defines LSFT to be "a test of all logic components, i.e. all relays and contacts, all trip units, solid state logic elements, etc., of a logic circuit from sensor through
,
' i and including the actuated device, to verify OPERABILITY". Hence, the definition of the LSFT would appear to require that all contacts be tested. However, in discussions with plant staff and GE personnel, it is apparent that these redundant contacts are not required to meet IEEE 279 design criteria. A failure of the redundant contacts will
not cause the RPS to be inoperable as a result of a ' single failur The inspector was informed by GE personr.al that the additional contacts were added for reliability, but that the later GE designs (i.e. late ! I i _ _ . _ . _ _ _ _ . - _ , , - - . -
" ~ ~ '
. ' . ( (
.
BWR4 and BWR5 and 6) use only the single contact desig . The weekly functional test for the APRM, SI-278-209, involves removing the Z34 trip reference card in the APRM circuitry to enable testing of the APRM high flux setdown trip. This trip is not required to be operable in Operational Condition 1. Instrument and Controls (I&C) personnel agreed to not perform this test in Condition 1, since this contributes to additional wear on APRM card . TS Table 3.3.1-1, Reactor Protection System Instrumentation, Functional Unit No. 2, APRM, contains a footnote (e), which specifies that an APRM channel is inoperable if there are less than 2 LPRM inputs per level or less than 14 LPRM inputs to an APRM channe The latter requirement causes an automatic inoperative signal to the APRM and this function is checked during the weekly functional tests. The requirement for two LPRMs per level is not automatic and is not explicitly controlled. A Reactor Engineering procedure RE-2TP-0017, " Bypassing of Drifting LPRM", contains a caution to ensure that there are at least two LPRMs per level per APRM channel. However, since Operations
-
or I&C personnel may also bypass LPRMs, the licensee will review to determine if additional controls are necessar The LSFTs do not test bypasses of RPS trip The logic for the following bypasses are not tested: 1) The MSIV closure trip bypass (which automatically bypasses the MSIV closure scram if the Mode Switch is not in RUN), 2) The Turbine Stop and Control Valve fast closure scram bypass (which automatically bypass these scrams if reactor power as determined by turbine first stage pressure is less than 24 percent power), 3) The Scram Discharge Volume (SDV) high level trip bypass (the operator can manually bypass this trip by a switch if the Mode Switch is in Refuel
or Shutdown).
A requirement to test the bypasses of RPS protective functions is not explicitly stated in the Technical Speci.fications although the requirement for the bypass is liste It is possible that a failure of some
.
. ( (
.
portion of the bypass circuitry could make an RPS trip inoperable, although it appears that more than a single failure is require The above bypass functions also have annunciators in the control roo This issue was addressed by the PP&L Surveillance Task Force and PP&L's position is documented in PLIS 13301 Issue No. 7, " Additional Testing" and PLIS 13,997
" Philosophical Issues Position Papers" dated January 30, 1984. The PP&L position is that RPS bypasses should be tested in the surveillance test program, and that the surveillance requirements in TS should be modified to incorporate these requirements. The inspector could not identify any further action being taken by the licensee to implement this positio . Technical Specification Table 3.3.1-1 footnote (j)
states that the Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure scram functions shall be automatically bypassed when turbine first stage pressure is less than 108 psig (or 17 percent of the value of first stage pressure in psig at valves wide open (V.W.0) steam flow), equivalent to about 24 percent of rated thermal power. ,This requirement is not addressed .in any surveillance requirements. The-pressure switches PSH-C72-2N003A-D are calibrated in I&C's preventive maintenance program on a 2 year interva The as-found setpoint on the calibrations sheets is 108 psig plus/minus 10 psig,.and hence, the setpoint is allowed to exceed the requirement of 108 psi The inspector determined that the FSAR and Standard Technical Specifications indicate that this function should be automatically bypassed at a turbine first stage pressure equivalent to 30 percent power (approximately 136.5 psig). In G0-200-003, Power Operations, there is a caution to ensure that the TCV FC/SV trip bypass annunciator clear prior to exceeding 30 percent power. It appears that 108 psig is a nominal trip setting and not a limit (or allowable value), but the TS do not reflect this. The TS should be revise Items 1, 4 and 5 are considered unresolved pending further review. (388/85-23-01) 5.2.3 HPCI Surveillance Review The inspector reviewed several surveillance procedures used to meet the channel functional test requirements for the HPCI system. The purpose of the review was to determine if the surveillance procedures test the entire channel as
,
, ,
( (
specified in TS 1.6, Channel Functional Test definitio The following procedures were reviewed:
--
SI-152-204, Monthly Functional Test of HPCI System Steam Line A DP Channel, PDIS-E41-N004 and PDIS-E41-N005
--
SI-152-201, Monthly Channel Functional Test of HPCI System Steam Supply Pressure Channels, PSL-E41-N001A-D, Rev. 0
--
SI-152-211, Monthly Channel Functional Test of HPCI Turbine Exhaust Diaphragm Pressure Channels, PSH-E41-N012A, B, C, D, Rev. 0
--
SE-180-205, Monthly Channel Functional Test of Reactor Vessel Level Channels LIS-B21-N024A-D, Rev. 1 In each of these tests, I&C technicians insert a simulated signal into the detector, f.e. pressure switch, level switch, etc. , and verify that the switch contact at the local panel changes state as the signal is applied. No attempt is made to verify actuation of associated channel relays, relay cor. tacts, or indicators. Contacts from these channel relays enter into the associated trip system logi Figure 2 (attached) is a simplified diagram of the HPCI turbine trip on high reactor vessel level, a two out of two trip logic. One channel of this logic includes the detector (B21-N0248), relay K45 and associated contact The channel ends where it joins in combinational logic with other channels, in this case, at the K45 contact in the K11 relay string. The CFT for this channel, SI-180-205, consists only of verifying that the contact for LIS-B21-N024B, changes state when a signal is applied to detector 821-N024 The associated relays and contacts are tested during the logic system functional test, on an 18 month interval. A brief review of several other surveillance procedures indicated that this method of performing CFT appears to be prevalent for ECCS isolation and actuation systems on both Unit A channel functional test is defined in T.S.1.6 as follows:
"A CHANNEL FUNCTIONAL TEST shall be:
a. Analog channels - the injection of a simulated signal into the channel as close to the sensor
,
. * . ( (~
.
as practicable to verify OPERABILITY including alarm and/or trip functions and channel failure trip b. Bistable channels - the injection of a simulated signal into the sensor to verify OPERABILITY including alarm and/or trip function The CHANNEL FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total channel steps such that the entire channel is tested".
A CHANNEL is not defined in T.S. However, various IEEE standards (IEEE 380,603,279) and PP&L's own position (plIS 13,997) identify the end of the channel to be where
" single protective action signals are combined".
In PLIS 13,997 dated January 30, 1984, the pP&L position for a Channel Functional Test was established as follows:
"A Channel Functional Test (CFT) must test circuitry f rem as close to the sensor as practicable to where the channel becomes part of the protective action logic. The CFT should not test protective action logic unless the only convenient point for .
verification of generation of the protective action signal is in that logi A Channel Functional Test should terminate where the channel trip signal combines with other channel signals in the protective action logic. (This can be the last relay in the channel and not the contact in the protective action logic)".
This position paper was signed by the senior management of the Nuclear Department. In May 1984, the I&C Supervisor presented a position paper to the Plant Operations Review Committee (PORC) at PORC meeting No 84-117. This position paper proposed to define the "end of*the channel for the purpose of CFT to be the input node of the coil of the actuated relay (s) which enter into combinational logic with logic provided by other channels". This position was accepted by PORC although a dissenting opinion was written indicating that this position does not comply with the PP&L position in PLIS 13,997. The CFTs identified above were written in accordar.ce with the policy approved by POR A concern about the adequacy of CFTs performed at Susquehanna was previously identified by the resident inspector in June 1983 (Inspection Report 50-387/83-15) and considered unresolved. Tests which only verify the ,
. __ _ . ( (
.
actuation of the detector's contact in the channel logic, 4 and not associated channel relays or other logic, do not meet the requirement of testing the entire channe Channel Functional tests for the HPCI actuation and isolation instrumentation systems are required to be performed on a monthly basis by T.S. 4.3.3.1 and 4.3. Failure to test the entire channel is a violatio (387/S5-28-03; 388/85-23-02) 5.3 Maintenance Activities The inspector observed portions of selected maintenance activities to determine that: the work was conducted in accordance with approved procedures; regulatory guides, Technical Specifications, and industry codes or standards. The following items were considered during this , review: Limiting Conditions for Operation were met while components or systems were removed from service; required administrative approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and QC hold points were established where required; functional testing was performed prior to declaring the particular component operable; activities were accomplished by qualified personnel; radiological controls were implemented; fire protection controls were implemented; and the equipment was verified to be properly returned to servic Activities observed included:
--
Replacement of Main Steam Line High Radiation Relay C72-K7B performed on September 16 and 19, 1985. (WA-V50735) The maintenance activity observed was performed in accordance with the applicable requirements and found acceptabl .0 TMI Action plan Requirements II.F.1 - Accident-Monitoring Instrumentation (Unit 2) The installation of containment pressure, containment water level and containment hydrogen accident-monitoring instruments was reviewed for Unit 1 in Inspection Report 50-387/82-3 The identical instruments were installed 198 for Unit 2 prior to issuance of an operating license in March, Based on the previous review performed on the Unit 1 installation, and inspector observation of the operable instruments in Unit 2, this item is considered close .0 Exit Meeting On October with 4,1985 the inspector discussed the findings of this inspection station managemen Based on NRC Region I review of this report and discussions held with licensee representatives, it was determined that this report does not contain information subject to 10 CFR 2.790 restriction _ .
-.- . _ _ . . _ _ _ . . . _ . _ ~ . _ _ .. - - . - . . . .
9t
. .
l y. - m , .
. . . . . . . . . . , . ..,.......... .....................
9..... ....... ................... .. ..,
** *
,.
*...
,', , , i s, . . . . '.a rh ,
t s ..r Li ... .ce *.'.i,. .
.
,
j r sj a i - !, el
*.r -. .. c, ..- l * '-.... .e %),te...
-
,
*
a . . . .
,
...
. .
,
. - - - : , ! .] * " ,al " .. =.
,..........
.
. '.' ! *.* '.t3 1 .. . . ..} .te I i i
~
*i' : * .'+
,
q .E'. s
.....r.;__......
,
* *.
O ,. .
.. t 3.. p(, .: .
r ,- f.;m; ,* fI.' , , ,, ,
.
,
.e ........g
.e r ,
,
*
1. h!V' . J l j,: . . .
.
.
..
,
,
.j . ' . . -..
l
.U a .
!ij F.. !
it I~~i i . !
*
* .1 tJ l ' ') . ~I e ; - = ,-
-
,.. . ,. .
.. . ., .
,.
. .... ,/u._......,.- .- J,, . e
.
. .'i.........;i , . . .i ._ t-. }.
. ..
q... - l . .1-() _ t . _. t . f i .
... -I
. 8 ,
. .
' :.. , -
( [' ,' r-
.,..
f G. . ..:
"'
.. ..,.. ..
-
.
s t--- -
,
i j .1 i .
.-e ,
o ,, , .. ., . s
,........
. ,3 , ,, u1, ,, .- . . , ,. , .,: ,
.,. ><
- * "c l 't .n. .,u_ ... ? %. .,...
: vi ..... -
;
.. .. .
-7. . .g
>e
- , .u.. ... .. e ;) ', i
't-I
, .
..
.
...,1'.- si n l .
, .
.t L.9.*M Ljt.4 "' 4 $'
l i .'MP'2.t J. .j_ .-.I "' :
-
1 1 l ' ,
,
.
'
r- 8 ! .., ; g L,v.v.M' ....t,"
-
m ;u,. r. ;r.-..c i., 'i...] o; 4 ;c ..;;.e; j -
:
51 n; .2.'t
. E..s.s(,... M , ,.'
i i o .n m
...
s a ; ,_ ..e .
.
.
,
l
.
l.,
; '
l
.-
,=-
,
u o.. , .,] 'T
, . i.s. .1 . . .'L.... '
.
e .r a r 'e* i ,. )' '.II .sc .d ...e .' _ , i l
,
. n. . ,. .
, m u n , L .c . .
------
I ,
'
' ..c u..:
*
s [ .n .u .
. . . .
r i 7- ,- .
~~
'I . . ,r ;,;;,c y 34 y, s" .. s
.
.[ .eliforl
.u. s.si ~ t, . :j
" #.c . . 4
,
'
.'. . i n. .u..: . q f l g . ..,,. . ,
c.u. 2 (.,L;. . . .
,
.
_,,_,
.. ,,,..,,,,,.
u.515.. t
-- ---
, . . ... g t . .a. u. . . s ( ,
i
..<
p.......e 1 . .,
.a. o.r.e .
,
,, u . ,
e,.. .A., u . ..u ' ,7 "5 re .., c7.;.1 d"22'*:s,4'
,
.
'7 "'
.;
j r.-
. ..
;
,
.
(ep h : 'a r. .wc. .,*=.*1n J .'k .n
.
i . .
;
o r *. .. . .'t. , . ..,r" ' ' .'" .,,. L . ., .
.i.. . 'sg .,
1 'I l ,r
,.'0
.n.. O.i .a ' *:g ,as r8 .n..,,p;.i.-
.o .s * .
'I ..n
h ' g - t
'A . '2f 8
, - - - j ,l ,7 : 8..#, . 91, c . ' . 5. . s .
#.L . , >.
, 8 I,'.*n' 'e' , ,
.
I
,
.,i, E t t .- .. E t t b-9
. . 5:25
** g( :n ( *$ 862E g .
, , c>. *
ch>- l ,
'
3,.
.,
.
.r
,
. ...t-i s I # ' .. l' .
l o as5 , l'..H*.. .
...
'
' '
.i sc l *
l
. .-:; L 11'.S ( , ,,,, 8 a ,s e.:,, 'n.a c e g .#=Mt.as
Y.a 4..e3 g;g fe,sj,j <.. ,, t 8
. . + .
et~ '
L'c ts -s.e>
--E E -s _
l At
,-
ea as . ', . .. g a..t > ei,s,._ . 4( .( a s.t3.( se.6Ka6
< a A' c>
s 8 8 2 (st a 9) gasseel
.I*' I .u.74609 , ,
'
8 3 4,
;- y- 'l srs. s'1 e, , , ,,g H8 1 e,,,,,, gg g, , , *
q .I "*RT ,,,, T s ,t, "" 'T "'" p, T "'"4, " i ". f ,",,""
,
'
_' ,
-
.~ is * u es sa te s
'. sera is
.: .. <554 I8*W v 's.94 4'
e ,e ., L3 i 0 M ga ,,a'S$44 gg 4'[ tat M ge t ' irr x - 7 w-n., f, .
..
. s'-
*"">
=annu':na- , u , .eu. = = , = =,ej,gg,'f:n== = u i == = = ,
o
.
. .o
'
'
.h.* ps.z .
r
,
-
. .,
. .
.. u \ .
, M-1 i
-
FIGURE 1 4,;
.
Y
. .
_ I;PS 'A' TRIP SYSTEM
+
* M. _ ) I . I I I I I I I .I r i i i .w.*EJs N w GGs.:wxrW7ml7At Nl I I
-
1,,, ..
_ _ _
,
,
. -
*
{ (
FIGUP.E 2
.
HPCI HIGH LE'.TL TUi.f:II E liif C
(
u s.c n .imt46
-- -
- N
/ I
"
{h -- gg E4t- V45 - - --~ -
,o q: .t c Tr.ir tut 9 cAhtsac t- ( g, K45 is a relay in one channel of the HPCI high reactor vessel level trip syste K56 (contact only shown) is a relay in the other channe K11 is the high reactor vessel level trip rela A contact from this relay activates a turbine trip rela :
.i
* .
f
_ .- _ _ _ _ _ , ., _ _ . . .
. /N ( '3 * -
l^1 Q l f $ *( MAR 51986
- . . , .
Docket Nos. -4h387 50-388 Pennsylvania Power & Light Company ATTN: Mr. H. W. Keiser Vice President Nuclear Operations 2 North Ninth Street Allentown, Pennsylvania 18101 Gentlemen: This letter concerns your November 15, 1985 letter in which you respondeo to the Notice of Violation identified in Inspection Report 50-387/85-28, 50-388/ 85-23, issued on October 17, 1985. The violation addressed the adequacy of channel functional tests (CFTs) on the High Pressure Coolant Injection (HPCI) syste In conjunction with NRR, Region I has reviewed your response and finds it unacceptable. Our position is that CFTs for instrumentation channels must test all components up to the point where single action signals are combined.
PP&L's methodology for CFTs for HPCI and other ECCS and Isolation actuation systems, excludes certain components (e.g. relays) in the channel upstream of the combinational logic.
We request that you resubmit within 30 days, a reply to this Notice of Viola-tion addressing the information required by the Notic In addition, as dis-cussed with Mr. Barberich of your staff, we have scheduled a meeting on March 14, 1986 at 10:00 a.m. in the Region I Offices, King of Prussia, Pennsylvania, to further discuss this issue. At this meeting, you should be prepared to dis-cuss your plans and schedule to correct the testing deficiencies in your CFTs for instrumentation channels. A discussion of specific examples of different tests would prove useful. Questions concerning this matter may be directed to Jack Strosnider, Region I Project Section Chief at 215-337-5128.
Your cooperation with us is appreciate
Sincerely, Original Signed By: Richard W. Starostecki, Director Division of Reactor Projects 0FFICIAL RECORD COPY LTR SUSQUEHANNA - 0001. /29/80 3.ECI l w o , ,a ~ 1n
~v *
If I I
I t' \ f'} / Pennsylvania Power &
. .
.
-
'
.
Light Company 2 CC: A. R. Sabol, Manager, Nuclear Quality frssurance / W. E. Barberich, Licensing Engineer / / T. M. Crimmins, Superintendent of Plant - SSES V A. J. Pietrofitta, General Manager, Power Production Engineering and Construction, Atlantic Electric / R. J. Benich, Services Project Manager, General ectric Company / B. O. Kenyon, Senior Vice President - Nuclear BryanA.Snapp,fsquire,AssstantCorporateCounsel/ William MatsonV Public Document Room (POR) LocalPublicDocume-tkoom(LPDR)[ NuclearSafetyInformatynCenter(NSIC) NRC Resident Inspector / Commonwealth of Pennsylvania / bec: Region I Docket Room (with c ncurrences) Management Assistant, DRMA DRP Section Chief M. J. Campagnone, NRR
'
g l RI:DRP RI:DRP @ BRP R1- P Jacobs/ba Strosnider QR7 3/ er
Sta ostecki e 3/ g/86 3/1/86 3/ /86 0FFICIAL RECORD COPY LTR SUSQUEHANNA - 0002. /29/80 }}