ML20134K191

Insp Rept 50-382/96-14 on 961201-970111.Violation Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20134K191
Person / Time
Site:	Waterford
Issue date:	02/07/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20134K171	List: ML20134K166 ML20134K183 ML20134K191
References
50-382-96-14, NUDOCS 9702130178
Download: ML20134K191 (27)

See also: IR 05000382/1996014

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ENCLOSURE 2

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U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-382

4 License No.: NPF-38

, Report No.: 50-382/96-14

j Licensee: Entergy Operations, Inc.

Facility: Waterford Steam Electric Station, Unit 3

Location: Hwy.18

, Killona, Louisiana

] Dates: December 1,1996 through January 11,'1997

Inspectors: L. A. Keller, Senior Resident Inspector

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T. W. Pruett, Resident inspector

C. E. Johnson, Reactor Inspector

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G. M. Good, Senior Emergency Preparedness Analyst

C. J. Paulk, Reactor Inspector

Approved By: P. H. Harrell, Chief, Project Branch D

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ATTACHMENT: Supplemental Information

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9702130178 970207

PDR ADOCK 05000392

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EXECUTIVE SUMMARY ,

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Waterford Steam Electric Station, Unit 3 i

NRC Inspection Report 50-382/96-14 l

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This routine, announced inspection included aspects of licensee operations, maintenance, )

engineering and plant support. The report covers a 6-week period of resident inspection. I

Operations

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• Observed operations activities were generally performed in a manner consistent

with safe operation of the facility (Section 01.1). j

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• Operations inappropriately signed off a condition report (CR) on a low pressure l

l safety injection (LPSI) Train B water hammer that occurred on November 19,1996, j

as a condition not affecting system operability. This conclusion was premature in l

that the cause of the water hammer, the repeatability of the pressure spike

experienced, and an analysis of the effect on system components had not been ,

performed (Section O2.4.5). l

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• On November 19 and 21, LPSI Train B experienced a water hammer and no actions '

were taken to discover the root cause until a subsequent water hammer event

occurred in LPSI Train A on December 13. This was despite clear evidence that the  ;

conditions that caused the water hammer would exist during an accident. This i

issue is unresolved pending further NRC review of the licensee's actions I

(Section O2.1b.5). .

• L'icensee analysis indicated that there was not reasonable assurance of ability to

remotely initiate shutdown cooling following a water hammer in the LPSI piping due

to potential pressure locking of LPSI flex-wedge gate valves. The inspectors

concluded that there was a potential common-rnode failure for pressure locking

flex-wedge gate valves in both trains of LPSI. This issue related to the licensee's

response to the water hammer events is unresolved pending further NRC review

(Section 02.1b.5).

Maintenance

• The inspector prevented a welding procedural violation by prompting craft personnel

to take a required interpass temperature reading (Section M1.2).

• The inspectors determined that the hydrogen analyzer calibration procedure was

inadequate. The discrepancies indicated a lack of rigor during the development of

maintenance procedures for the hydrogen analyzer and constituted preconditioning.

A violation was identified for not maintaining an adequate test procedure

(Section M1.3).

• The licensee's participation in the Arkansas Nuclear One (ANO) Technical

Specifications (TS) audit was a positive initiative to assess the adequacy of their

surveillance program for the plant protection system (Section M3.1).

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The licensee's determination that the channel functional test was not in accordance

with the licensing basis and the subsequent corrective actions were appropriate.

The failure to perform channel functional tests on the core protection calculators

(CPC) in accordance with the licensing basis is considered a noncited violation

(Section M3.1).

Enaineerino

The system engineer did not observe surveillance testing of the hydrogen analyzer

and was not informed when trouble shooting was performed when the analyzer

failed the test. Also, the system engineer did not identify in reviewing the test

procedure that it was preconditioning the test (Section M1.3).

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• Engineering support in investigating the November 19 and 21 water hammer l

incidents in LPSI Train B was poor. The lack of rigor and questioning attitude  !

regarding the cause of these water hammer incidents left the LPSI system

vulnerable to further water hammer and loss of shutdown cooling function.  !

Engineering support following a subsequent water hammer in LPSI Train A was I

significantly better, including a good recommendation for modifications to I

flex-wedge gate valves (Section O2.1).

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Plant Sucoort I

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• A poor radiation protection (RP) work practice was observed in which maintenance

technicians breached an overhead contaminated system without face shield

, protection (Section M1.2).

• The licensee substantially improved the quality of permanent and temporary lighting

in the protected area. However, the f ailure of a security patrol officer to report a

lighting deficiency is considered a violation of TS 6.8.1.a (Section S1.1).

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Report Details

Summarv of Plant Status

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The plant operated at 88 percent power on December 6 and 7 to perform CPC channel

functional checks. On December 16 and 17, the plant operated at 63 percent power to j

perform maintenance on the main feedwater pumps. The plant operated at essentially  ;

100 percent power during the remainder of this inspection period. l

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l. Operations

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l 01 Conduct of Operations I

01.1 General Comments (71707) i

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i Using Inspection Procedure 71707, the inspectors performed frequent reviews of  ;

ongoing plant operations, control room board walkdowns, and plant tours. j

Observed activities were generally performed in a manner consistent with safe  ;

operation of the facility. Housekeeping and material condition were generally good. l

l Operators were familiar with causes for lit control room annunciators. Preparations  !

f for cold weather were adequate. Shift turnover and plan-of-the-day meetings were

professional and informative. However, certain activities appeared to be in violation

of NRC requirements or indicate problem areas, as discussed below.

01.2 Nuclear Auxiliarv Ooerator Tours (71707)

The inspectors observed two nuclear auxiliary operators during the performance of

plant tours. The inspectors noted that the auxiliary operators were attentive to

, plant equipment and material discrepancies during the tours. Several minor

discrepancies, involving lighting, minor leakage from pumps and valves, and general

plant cleanliness, were identified and resolved. Operators were knowledgeable of

plant conditions and operating trends of plant equipment. )

O2 Operational Status of Facilities and Equipment

02.1 LPSI System Nitroaen Pockets and Water Hammer Events i

a. Insoection Scone (71707,37551)

The inspectors reviewed the circumstances surrounding the water hammer events

that occurred in LPSI Train A on December 13 and in LPSI Train B on November 19

and 21,1996. Additionally, the inspectors reviewed the licensee's operability

analysis that was completed to evaluate the presence of nitrogen gas pockets in

LPSI Train B.

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b. Observations and Findinos

b.1 LPSI Train A Water Hammer

On December 13, during a routine surveillance start of LPSI Pump A, a pressure

spike caused by a water hammer occurred in the system piping. An operator i

observing the plant computer display at the time the pump was started, noted that

LPSI pump discharge pressure briefly reached 317 psig (shutoff head of the pump is

approximately 213 psig). The operator at the pump, as well as the operators in the ,

control room, heard a banging noise after the pump was started. As a result of the '

water hammer, the shift supervisor declared LPSI Train A inoperable and

appropriately entered TS 3.5.2. '

The LPSI Train A piping was inspected by engineering personnel from the pump to

the containment penetrations and no visible signs of piping or hanger damage was

noted. Ultrasonic testing (UT) was subsequently performed at several high-point

vent areas. The horizontal piping run containing vent Valves Sl-133A and -134A

was found to contain an apparent void in the pipe (12 inches and 14 inches of prc,

respectively). The void was sampled and found to be approximately 97 percent -

nitrogen.

Valves SI-133A and -134A were then used to fully vent the piping and UT

confirmed the piping was full of water. The scope of the UT was then expanded to

include the high points of the LPSI Pump A suction, which revealed the piping was

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full. LPSI Pump A was subsequently started with no abnormal noise or pipe

movernent. Based on the UT results and successful pump start, LPSI Pump A was 3

declared operable on December 14 and TS 3.5.2 subsequently exited. On  !

December 14, the licensee conducted UT on portions of the LPSI Train B piping and  !

the discharge of the High Pressure Safety injection (HPSI) Pump A/B discharge  ;

piping to ensure the piping was full. No voids were found. i

The licensee determined that the source of the nitrogen was leakage of

nitrogen-saturated water from the safety injection tanks (SIT). The SITS contain a

nitrogen blanket pressurized at approximately 650 psig. The SIT outlet valves are  ;

open and the SIT outlet piping connects to a common injection line with LPSI and  !

HPSI. Therefore, the nitrogen-saturated SIT water can freely communicate back to i

LPSI Header Check Valves SI-142A(B) and -143A(B). Since the solubility of I

nitrogen in water is greater at higher pressures, the licensee concluded the nitrogen

pockets were the result of nitrogen coming out of solution in the relatively low

pressure of the LPSI system (less than 50 psig when pump is not running) when the

water leaked backward (i.e., from a high to a low pressure area) through a check

valve and an isolation valve.

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b.2 LPSI Train B Nitroaen Pockets

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in an attempt to identify all nitrogen pocket locations, the licensee again expanded

, the scope of the UT program on December 18 and discovered nitrogen pockets in

j the LPSI Train B piping at Penetrations 36 and 37. The pockets were located at the I

high points between Flow Control Valves SI-138B and -139B and the inside i

Containment Isolation Check Valves SI-1428 and -1438. The arc length of the gas

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pocket at Penetration 36 was 11.3 inches over a length of 18 feet, which equates

to a volume of 2.54 cubic feet. The arc length of the gas pocket at Penetration 37  :

was 10 inches over a length of 16.5 feet, which equates to a volume of 1.74 cubic

i feet. The locations of these particular nitrogen pockets were such that they could

not be removed due to the lack of vent valves in the affected section of piping or

the ability to flush them at power. CR 96-1965 was written to document and

i disposition the presence of these nitrogen pockets. On December 18, the licensee '

initiated an operability evaluation in accordance with Site Directive W4.101,

" Operability / Qualification Confirmation Process," for the LPSI Train B nitrogen

pockets.  ;

l~ The W4.101 evaluation concluded that the existing nitrogen pockets would cause a  !

. pressure transient on a LPSI Pump B start that would slightly exceed the design

j pressure of the system (650 psig), but would not prevent the LPSI system from

i providing emergency core cooling in the event of a loss-of-coolant accident. The

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basis for this conclusion was that the very scenario of concern had occurred on

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November 21, in that a start of LPSI Pump B resulted in a pressure spike of

. 660 psig, which did not result in any obvious component / piping / system damage.  ;

, The licensee believed that the conditions that resulted from the November 21  ;

1 pressure transient bounded any future transient.

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The inspectors reviewed the operability evaluation completed by the licensee to l

independently assess the continued operability of LPSI Train B with a nitrogen

pocket in the system piping. The specific concern was the capability of the system

to physically withstand another water hammer event. At the end of this inspection

period, a review of the licensee's operability evaluation and the operability of the

LPSI systems by NRC personnel was ongoing. Review of this aspect of the

licensee's response to the water hammer events remains unresolved pending the

completion of the NRC's review (50-382/9614-01, Example 1).

The W4.101 evaluation also addressed concerns related to potential pressure

locking of flex-wedge gate valves in the supply and return lines of the shutdown

cooling heat exchanger (Valves SI-125B and -412B) and the effects on Crosby

Relief Valve SI-132B. The W4.101 evaluation was completed on December 20 and

concluded that shutdown cooling entry could be affected since there was no

reasonable assurance that Valves SI-1258 and -412B would not be pressure locked

following a water hammer when LPSI Pump B started.

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The W4.101 evaluation listed the following corrective actions. At the end of this

inspection period, the licensee was pursuing the completion of the items.

• Periodically verify by UT that the arc length of the gas pocket at

Penetration 36 does not exceed 11.8 inches and the gas pocket at

Penetration 37 does not exceed 10.4 inches (as of the end of the inspection

period the UT frequency was every 3 days);

• Enter the appropriate limiting conditions for operation (TS 3.9.8.2, 3.4.1.3,

and 3.4.1.4) for potential ;noperability of flex-wedge Gate Valves SI-125B

and -412B;

• Initiate a repair package to install vent lines at Penetrations 36,37,38,and

39 during the next refueling outage (currently scheduled for April 1997);

• Design engineering to perform a detailed transient analysis that accurately

models the as-found conditions; and

• Determine additional long-term corrective actions through CR 96-1965.

b.3 Crosbv Relief Valve Sl-132B Concern

Valve SI-132B is the LPSI Train B discharge header thermal relief, which is set at

650 psig. This valve had been identified in CR 96-0463 as having an incorrectly set

• blowdown ring. Tt issue of Crosby relief valve blowdown ring discrepancies is

discus' sed in NRC ..spection Report 50-382/96-202. This setting did not affect the

set pressure of the valve, but effects the pressure at which the valve reseats after

opening. The specified closing pressure was approximately 585 psig (90 percent of

set pressure).

The concern was that a water hammer would cause the relief valve to open and the

incorrectly set blowdown ring would prevent the valve from reciosing, thereby

diverting LPSI flow from the vessel. Since the shutoff head of the LPSI pump is

approximate!y 213 psig, the closing pressure of Relief Valve SI-132B would have to

be less than 33 percent of set pressure for the valve to not reclose. Based on the

magnitude of the blowdown ring error (off by 10 notches) and previous bench

testing of similar valves (worst case reset was 74 percent of set pressure), the

licensee concluded that Relief Valve SI-132B would reset under the scenario of

concern.

The inspectors reviewed the licensee's evaluation and conclusions with respect to

Valve SI-1328 and concluded that they were acceptable.

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b.4 Flex-Wedae Gate Valves SI-125A(B) and -412A(B) Concern j

The inlet and outlet shutdown cooling heat exchanger isolation valves, Sl-125A(B)

and -412A(B), are motor-operated, flex-wedge gate valves and were identified by  :

the licensee as being susceptible to pressure locking in the response to Genenc

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Letter 95-07. i

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The concern with pressure locking was that a water hammer would generate a '

pressure wave that would be transmitted to Valves SI-125A(B) and -412A(B) and

allow pressure to be trapped in the valve bonnets, thereby eliminating the ability to j

remotely open the valves. On December 20, the licensee concluded that there was l

no reasonable assurance that pressure locking of the Train B valves would not occur  !

during the scenario of concern and, therefore, declared the valves inoperable. A

modification was initiated to install vents in the valve bonnets to prevent pressure  !

locking, which was completed and Valves SI-125B and -4128 declared operable on

December 22. The licensee decided not to perform the modification on the valves

in Train A since voids had not been detected in Train A and since periodic venting

and UT was determined to be adequate to prevent water hammer until the  ;

modification was completed.

As of the end of this inspection period, the licensee was venting both trains of LPSI  ;

once per day and performing UT on both trains of LPSI every 3 days to verify that

LPSI Train A was water solid and the nitrogen pockets in Train B were not

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expanding.

The issue of potential pressure locking of the shutdown cooling heat exchanger inlet

and outlet valves causing a loss of shutdown cooling is another aspect of this

unresolved item, related to the licensee's response to the water hammer events,

pending additional review by NRC personnel (50-382/9614-01, Example 2).

b.5 LPSI Train B Water Hammer Event

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On November 19, while starting LPSI Pump B to recirculate the refueling water

storage pool (RWSP) for sampling, a water hammer occurred in the downstream

piping. Control room operators reported that control room Gauge SI-IPI-036 spiked

up to approximately 500 psig. Normal pump operating pressure of approximately

160 psig was observed by the operators for the duration of this pump run.

Subsequently, on November 19, CR 96-1831 was written to disposition this event. 4

On November 20, the shift supervisor signed off CR 96-1831 as a condition that did

not affect operability of the equipment / system. The stated basis for this conclusion

was: "The pump operated at normal pressure when running. The system engineer

was informed and he stated that the start pressure appeared to be a little high.

Currently, some air voiding in the pipe / pump / instrument line is suspected, but not

enough to cause an operability concern. No water hammer was noted by the shift." ,

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The inspectors considered this conclusion premature in that the cause of the water

hammer / pressure spike, the repeatability of the pressure spike experienced, and an

analysis of the effect on system components (i.e., flex-wedge gate valves and other  !

components) had not been performed. The inspectors noted that the crew on shift

at the time of the event associated a water hammer as a " loud banging noise" and i

did not consider this transient a water hammer due to the lack of audible indication.

The inspectors concluded that whether the event was termed water hammer or

pressure spike, the magnitude was sufficiently above normal established parameters

to warrant a thorough investigation.

On November 21, LPSI Pump B was again used to recirculate the RWSP. Prior to

starting the pump, the Train B piping was vented and a strip chart recorder was

installed to closely monitor system pressure. The subsequent pump start resulted in

a pressure transient of 660 psig, as recorded on the strip chart recorder. Shortly

after this pump run, LPSI Train B Flow Control Valve SI 139B was found partially

open because of a valve mispositioning error by the operations crew.

Valve SI-139B was closed, LPSI Pump B was restarted, and no pressure transient

was experienced. Following this pump run without a water hammer, the licensee

took no further tangible efforts to discover why water hammers occurred with

Valve SI-139B open until the LPSI Train A water hammer event occurred in

December.

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The inspectors noted that Valve SI-139B receives an automatic open signal during a j

safety injection actuation signal and the valve opens before the pump starts. These

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automatic actions would reestablish the same system configuration that existed  !

when significant water hammers occurred on November 19 and 21. The inspectors

noted that there was clear evidence that the cause of the water hammers existed

downstream of Valve SI 139B, yet no tangible effort was made to ascertain the l

cause until a subsequent water hammer occurred in LPSI Train A on December 13. l

The inspectors concluded that the failure to adequately investigate the cause of the l

LPSI Train B water hammers left the system vulnerable to future water hammer

incidents and potential system operability concerns. As discussed in

Section O2.1b2 above, there was no reasonable assurance that loss of shutdown i

cooling would not occur due to pressure locking of the shutdown cooling ]

flex-wedge gate valves following a pressure transient. This aspect of the licensee's l

response to the water hammer events is unresolved pending additional review by I

NRC personnel (50-382/9614-01, Example 3). l

The licensee informed the inspectors at the exit meeting that not all engineering

efforts to determine the cause of the November 19 and 21 water hammers stopped

following the repositioning of Valve SI-139B. The licensee stated that between the

November and December events, the LPSI system engineer held discussions with

Chemistry and others into the possibility of nitrogen being responsible for the water

hammers, and that absent the December 13 event, this line of questioning would

have eventually led to the discovery of the nitrogen pockets. The inspectors could

not confirm or deny the system engineer's possible intentions, but noted there was

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nothing documented in CR 96-1831 nor were there any tangible actions taken (i.e.,

samples drawn, UT performed, etc.) to confirm / quantify possible nitrogen intrusion I

into the LPSI system prior to the December 13 event.

c. Conclusions

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The inspectors concluded that it was inappropriate for operations to sign off the CR

on the LPSI Train B water hammer that occurred on November 19, without pursuing

the identification of the root cause of the water hammer events. The licensee's

failure to adequately pursue the cause of the November 19 and 21 water hammer

events could have resulted in subsequent water hammers during system response

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to an accident.

The licensee's response to the water hammer that occurred in LPSI Train A on

December 13 was significantly better. Sesequent investigations discovered

nitrogen gas pockets at various high points in the LPSI system. The licensee was

unable to vent two pockets of nitrogen in the LPSI Train B piping near the

containment penetrations and, therefore, LPSI Train B was still vulnerable to water

hammer in the event of a safety injection actuation signal. The operability of the

system and the adequacy of previous corrective actions are unresolved issues. The

licensee concluded that the resulting water hammer, although exceeding system

design pressure, would not prevent LPSI Train B from providing emergency core

cooling. Modifications of the LPSI Train B flex-wedge gate valves for the shutdown

cooling system were completed due to pressure locking concerns; however, the

LPSI Train A was not completed. The potential for common-mode failure of

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shutdown cooling is an unresolved issue.

08 Miscellaneous Operations issues (92901)

08.1 The inspectors conducted a survey of the licensee's TS interpretations and

determined that none of the documents contained informal references to NRC

review and approval without formal NRC documentation. The inspectors

emphasized to the licensee that any informal reference to NRC review and approval

in a TS interpretation is not recognized by the Commission and is not an acceptable

practice.

08.2 (Closed) Violation 50-382/9517-01: failure to acknowledge fire protection panel

alarms. This violation involved the failure of control room operators to recognize

and announce fire protection panel alarms affecting the turbine building. In  ;

response to the violation, the licensee revised procedures to require operators to

verify the extent of fires using the fire detection computer, added a strobe light to

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the fire detection panel, and developed required reading material describing the

event. The inspectors observed that the strobe light was effective in gaining i

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operator attention to the fire detection panel and that operators were utilizing the

fire detection computer to determine the extent of potential fires. The inspectors

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determined that the licensee's corrective actions were satisfactory to address this

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08.3 IClosed) Violation 50-382/9605-02: control room personnel unaware of activities  !

affecting Emergency Diesel Generator A. This violation irvolvec' the operation of  ;

the emergency diesel generator fuel rack override lever by (1 instructor and

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maintenance personnel without the consent of the control rum. In response to this J

violation, the licensee counseled the individuals involved, discussed the event with

the training department, and issued a plant manager memorandum to all site

personnel reenforcing expectations about the operation of plant equipment. The i

inspectors determined that the licensee's corrective actions were satisfactory to

address this violation. .,

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II. Maintenan,c_e

M1 Conduct of Maintenance

M 1.1 _ General Comments

a. Inspection Scoce (62707,61726)

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The inspectors observed all or portions of the following maintenancs and I

surveillance activities:

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MI-003-223 Core Protection Calculator Response Time Verification

WA 01150587 Installation of a Vent Valve in Charging System

WA 01150409 Replacement of Charging Pump Discharge Relief

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ME-003-431 Containment Hydrogen Analyzer Functional Test and

Calibration

WA 01153825 Troubleshoot Hydrogen Analyzer Pump A Low

Alignment Discharge Pressure

b. Observations and Findinos

in general, the inspectors found the conduct of maintenance and surveillance to be

adequate. All activities observed were performed with the work authorization (WA)

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package and/or test procedures present and in active use. Technicians appeared

experienced and knowledgeable of their. assigned tasks. When applicable,

appropriate radiation control measures were implemented. The inspectors observed

supervisors monitoring job progress and quality control personnel were present i

whenever required by procedure. However, certain activities violated NRC  ;

requirements or indicated performance problems, as discussed below.

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M1.2 Charaina Pumo Relief Valve Reolacement

a. Inspection Scoce (62707)

The inspectors observed the replacement of Charging Pump B Discharge Relief

Valve CVC-1928. The inspectors observed removal and installation activities,

reviewed the applicable work packages and system drawings, and interviewed

selected personnel.

b. Observations and Findinas

On December 10,1996, the inspectors observed maintenance technicians

breaching an overhead section of the char 0i ng system, without protective face

shields, during removal of the existing charging pump discharge relief valve and

piping / flange connection. The inspectors questioned the RP technician who was in

the area monitoring the work activity about the observed practice. The RP

technician informed the inspectors that procedures did not specifically require

personnel to wear protective face shields when breaching a system. An RP ,

supervisor also confirmed the RP technician's statement. The inspectors expressed

concern to the RP supervisor regarding the potential for personnel contamination

and/or injury due to this work practice. The licensee subsequently agreed that this

was a poor work practice. The licensee informed the inspectors that they initiated a

CR to review this issue.

, Additionally, the inspectors noted that the bolts and nuts removed from the flange

were not the type of material specified by Drawing E-3029-LW3-CH-2. The j

inspectors were informed that Document Revision Notice (DRN) M-9502513 ,

implemented the material change. The inspectors found that the drawing was l

stamped with the DRN number; however, the inspectors questioned the licensee as 1

to why the DRN was not included in the work package and why the drawing was

not revised after a year. The inspectors were informed that: (1) the subject DRN

was inadvertently omitted, and (2) Design Engineering Procedure NOECP-306,

" Document Revision Notices," Revision 4, allows a time period for up to 18 months

for noncritical drawings to be revised; therefore, no procedural violation was

identified.

The inspectors observed fit-up and welding activities for Field Weld SW-17A (socket

weld) during installation of the new charging pump discharge relief valve and

associated piping. The inspectors noted that after completion of the first weld pass

for Weld SW-17A, the maintenance technician (welder) was starting to initiate the

second weld pass without verifying interpass temperature (350 F maximum) in

accordance with Weld Procedure WPS E-P8-A8. The inspectors stopped the

maintenance technician before the second weld pass was initiated and questioned

him if the interpass temperature was verified. The inspectors noted that there was

no "tempil stick" or pyrometer in the work area for use by the maintenance

technicians. Maintenance technicians in the area sent a maintenance assistant to

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get a pyrometer. The licensee confirmed that absent the inspector's prompting the  !

i interpass temperature would not have been taken.

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l c. Conclusions

. A poor RP work practice was observed in which maintenance technicians breached

} an overhead contaminated system without face shield protection. The inspectors

i prevented a welding procedural violation by prompting craft personnel to take a '

! required interpass temperature reading.

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M1.3 Calibration of Hydroaen Analyzers

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Insoection Scope (61726,37551)

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The inspectors cbserved the performance of the Hydrogen Analyzer Train A

calibration in accordance with Procedure ME-003-431, "Co - " ment Hydrogen

Analyzer Functional Test and Calibration," on December 3' , 66,and

trouble-shooting activities involving Hydrogen Analyzer Pur, A discharge pressure

on January 3,1997, in accordance with WA 01153825.

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b. Observations and Findinos

The instrument and controls foreman was present during portions of the calibration

and all of the trouble shooting. The system engineer did not observe the

surveillance and was not informed of the trouble shooting activities. Several

procedure discrepancies were noted during the performance of the surveillance test.

Procedure ME-003-431, Section 8.2.11, required that the hydrogen analyzer loop

and measurement flows be verified and adjusted if necessary prior to the

performance of the calibration. The inspectors noted that the technicians adjusted

l the loop flow from 3.8 to 4.0 scfh prior to performing the hydrogen analyzer

calibration and that the procedure did not specify an acceptable as-found flow rate

for either loop flow or measurement flow. The inspectors noted that returning the

gas flow to the technical manual referenced values prior to calibration was

preconditioning of the hydrogen analyzer and invalidated the as-found percent

hydrogen data obtained by the technicians. The licensee agreed that the

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adjustment on the loop flow preconditioned the hydrogen analyzer and stated that a

revision to the calibration procedure would be performed to ensure as-found percent

hydrogen data was obtained prior to adjusting hydrogen analyzer flow rates.

Procedure OP-903-120, " Containment and Miscellaneous System Quarterly IST

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Valves Test," Section 7.5, required that the licensee verify the hydrogen analyzer

loop flow greater than or equal to 1 scfh during stroke testing of the containment

}' dome hydrogen sample valve. The inspectors noted that Technical Manual

Section 3.5, " Pressure Regulation," required that the loop flow rate be set at 4 scfh

and that verification of 1 scfh instead of 4 scfh during quarterly inservice testing

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(IST) could allow an adverse condition to go uncorrected in that partial opening of

the sample valve may allow 1 scfh but not 4 scfh. The licensee stated that a

review of @ testing procedure would be performed to determine if a different

sample flow rate should be specified in Procedure OP-903-120.

The inspectors noted that Teleydyne Analytical Instruments Technical Manual,

Section 3.5, stated that the pressure in the return loop is maintained at 10 psig

above containment pressure in order to return gas and water to containment at

positive pressure and to prevent back pressuring the system. The inspectors

observed that the hydrogen analyzer control panel outlet pressure indicated that the

return pressure was approximately 1 psig above containment pressure. The

inspectors identified that the technicians did not note the abnormal outlet pressure

reading and determined that Procedure ME-003-431 did not require that the

technicians verify whether or not the hydrogen analyzer pump developed sufficient

discharge pressure to ensure the sample gas was returned to containment.

In response to these observations, the licensee: (1) stated that

Procedure ME-003-431 would be revised to require recording of the hydrogen

analyzer inlet and outlet pressure, (2) initiated a condition identification to document

the discrepancy, and (3) performed trouble shooting to verify the actual pressure

and flow rates of the hydrogen analyzer.

The inspectors observed the licensee perform the recommended technical manual

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testing as part of trouble-shooting activities associated with determining why the

hydrogen analyzer return pressure was not 10 psig above containment pressure.

With 5 psig nitrogen pressure applied to the hydrogen analyzer inlet, the following

results were obtained:

Test Location Actual Reauired Per Technical

Manual

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Pump Suction 2.83 1 psig

Pump Outlet 16.0 15-17 psig

Sample Pressure 4.41 4.0 psig

Loop Flow 4.4 Above 5.0 scfh

Sample Flow 0.25 scfh Not Specified

Return Pressure 15.5 psia Not Specified

Containment Pressure 15.0 psia Not Specified

Based on the results of trouble shooting, the licensee: (1) stated that an 18-month

repetitive task would be developed to ensure the hydrogen analyzer pressure

regulators were properly adjusted to maintain the required sample and measurement

flow rates, (2) determined that the hydrogen analyzer pump developed an adequate

discharge pressure, (3) determined that the low return header pressure was due to

the effects of containment pressure and the location of the return loop pressure

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transmitter, and (4) initiated an additional condition identification to perform testing

on Hydrogen Analyzer Train B.

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l The failure to provide a procedure for calibration of the hydrogen analyzers, which

l properly implements the testing recommended by the technica! manual, is a

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violation of TS 6.8.1 (50-382/9614-02).

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l c. Conclusions

The inspectors determined that the hydrogen analyzer calibration procedure was

inadequate since several procedural discrepancies existed. Collectively, the

discrepancies indicated a lack of rigor by maintenance during the development of

procedures for the hydrogen analyzer and by system engineering during review.

M3 Maintenance Procedures and Documentation  !

M 3.1 Inadeauate Channel Functional Test Procedure For CPC

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a. Insoection Scoce (61726)

The inspectors reviewed the circumstances surrounding the licensee's identification

that three of the four CPC reactor protective channels were inoperable due to an

inadequate TS surveillance procedure.

b. Observations and Findinas

The CPCs are digital computers that calculate local power density and departure

from nucleate boiling ratio (DNBR). A CPC is installed in each of the four reactor

protection channels. The calculated DNBR and local power density are compared

with trip setpoints for initiation of a low DNBR trip and the high local power density

trip. Each CPC receives the following inputs: core inlet and outlet temperature,

pressurizer pressure, react::t coolant pump speed, excore nuclear instrumentation

power, selected control element assembly positions, and control element assembly

deviation penalty factors.

l While assisting ANO personnel who were performing an audit of plant protection

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system TS surveillance compliance, Waterford 3 personnel discovered an issue

related to the TS surveillance channel functional check for the CPCs that was

relevant to Waterford 3. The issue involved whether all the various inputs to the

CPC were required to be manipulated during the 18-month channel functional test

specified by TS 4.3.1.1, or if it was acceptable to manipulate the excore nuclear

instrumentation input only, and take credit for testing " overlap" for the other sensor

inputs, which was the current practice.

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Waterford 3 TS for the CPCs includes the following statement: "This CHANNEL

FUNCTIONAL TEST shallinclude the injection of simulated process signals into the

channel as close to the sensors as practicable to verify OPERABILITY including

alarm and/or trip functions." The Waterford 3 testing regime had taken credit for l

testing " overlap" for the 18-month channel functional test for all of the CPC inputs I

except excore nuclear instrumentation. Overlap testing employs a series of

sequential, o"erlapping tests of individual sections of the channel which, when

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combined, tas'.'d the entire channel. The ANO Safety Evaluation Report indicated

that overlap tests for the CPCs were inadequate and that a functional operation

check from C7C sensor inputs to the trip output would be reouired to adequately

ensure that the CPCs were operational. The Waterford 3 Safety Evaluation Report

indicates that Waterford 3 is to meet the requirements on CPCs in the ANO Safety

Evaluation Report; therefore, overlap tests for the CPCs are also inadequate at

Waterford 3. The licensee, therefore, concluded that CPC Channels A, B, and C  ;

were inoperable pending a satisfactory channel functional test. CPC Channel D was  ;

deemed operable because it had successfully passed the reactor trip response time l

test during the last refueling outage. The reactor trip response time test adequately I

tests the char,nel using all the inputs, but is only performed on one CPC channe1 per

18 months.

On December 5,1996, the licensee declared CPC Channels A,B, and C inoperable

due to the failure to adequately perform Surveillance Requirement 4.3.1.1 and

entered the action requirements of TS 3.3.1 and 4.0.3. TS 3,3.1 requires at least

two CPC channels operable or entry into TS 3.0.3, which requires that within

, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, action be initiated to place the unit in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

' However, TS 4.0.3 allows the action requirements to he delayed up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to

comp!e's the surveillance. On December 6, testing was satisfactorily completed on  !

Channel A by utilizing the reactor trip system response time test, which is normally

performed during refueling outages. The inspectors verified that appropriate  !

precautions were taken to perform this surveillance at power. Performance of this

test required a power reduction to 88 percent due to the necessity of taking both

channels of the control element assembly calculator system out of service for the

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test. The restoration of Channel A resulted in two operable channels, which is

allowed under TS 3.3.1. Channels B and C were satisfactorily tested and returned

to service on December 6 and 7, respectively. I

The inspectors reviewed the relevant documentation in the Waterford 3 and ANO

Safety Evaluation Reports and the Waterford 3 surveillance test procedures for CPC.

The inspectors concluded that the failure to adequately test all the sensor inputs to

the CPCs during the charinel functional test is a violation of TS 4.3.1 A. This

licensee-identified and corrected violation is being treated as a noncitd ;tiolation,

consistent with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the

violation was identified by the licensee, was not willful, actions taken as a result of

a previous violation should not have corrected this problem, and appropriate

corrective actions were completed by the licensee (50-382/9614-04). l

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c. Conclusions

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The licensee's participation in the ANO TS audit was a positive initiative to assess

the adequacy of the Waterford surveillance program for the plant protection system.

The licensee's determination that the channel functional test was not in accordance

with the licensing basis and the subsequent corrective actions were appropriate.  ;

The failure to perform channel functional tests on the CPCs in accordance with the I

licensing basis was a noncited violation.

M4 Maintenance Ste'f Knowledge and Performance

M8 Miscellaneous Maintenance issues (92902)

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M8.1 (Closed) Insoection Followuo item 50-382/94402-02: failure to follow an

installation weld detail. The inspectors previously identified a program weakness  ;

regarding a failure to follow an installation weld detail during replacement of piping. {

The inspectors performed an inspection on a portion of replaced piping between the  !

high-pressure turbine and first-stage feedwater heaters. The inspectors observed  !

that Weld FW-20A was not conducted in accordance with the drawing. This  !

resulted in the condition of an undressed, notched flame-cut surface on the edges }'

of the hole, through the pressure piping which was not in accordance with the

drawing. This condition was not identified by the responsible craft, quality control

(QC), or supervision. The licensee documented this condition in CR 94-337. The

licensee had committed to the following: ,

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' Conduct trainin0 for all craft personnel (fitters / welders) involved in cutting i

and welding processes, and i

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Revised Procedure MM-001-056 to require QC to verify the ID of the half

couplings and ID match the hole cut of the sockolet.  ;

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The inspectors found that the licensee had closed CR 94-337 before the

commitments were implemented. The licenses initiated CR 96-1452 as a result of {

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the inspectors' finding. CR 96-1452 indicated that the Waterford 3 welding manual  !

would include appropriate guidance in Design Engineering Administrative Manual

(DEAM), Appendix 2, E-TCG, " Thermal Cutting and Gouging."

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The inspectors reviewed DEAM, Appendix 2 (E-TCG and E-GWS-1) and determined I

that the document provided adequate instructions and details for thermal cutting '

and gouging. The inspectors also determined procedural guidance included in l

DEAM, Appendix 2 was adequate to prevent recurrence for safety- and

nonsafety-related components.

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- M8 '2 (Closed) Violation 50-382/9508-01: f ailure to follow procedures to ensure adequate

storage of loose items and currect usage of measuring and test equipment (M&TE).  !

This violation involved the licensee's f ailure to ensure loose items were adequately I

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secured in safety-related areas and to ensure out-of-calibration M&TE was not used i

for testing. In response to the failure to secure loose items, the licensee issued a i

site-wide newsletter, performed training during shop meetings to all personnel, and

revised the construction department craft guide handout. In response to the failure

to use the correct M&TE, the licensee provided training to personnel on procedural

adherence and revised the maintenance procedure to provide additional clarification  ;

on M&TE calibration requirements. The inspectors determined that the licensee l

implemented effective corrective actions for this violation.

Ill. Enaineerina

E2 Engineering Support of Facilities and Equipment

E.2.1 Review of Facilitu and Eauioment Conformance to UFSAR Descriotion

A recent discovery of a licensee operating a facility in a manner contrary to the

UFSAR description highlighted the need for a special focused review that compares

plant practices, procedures and/or parameters to the UFSAR descriptions. Wiill.e

performing the inspections discussed in this report, the inspectors reviewed the

applicable portions of the UFSAR that related to the areas inspected. The

inspectors verified that the UFSAR wording was consistent with the observed plant

practices, procedures and/or parameters. No anomalies between the UFSAR and

operation of the facility were identified.

. E8 Miscellaneous Engineering issues (92903)

ES.1 (Closed) Violation 50-382/9607-02: failure to perform adequate control room

envelope testing. This violation involved the licensee's failure to perform control

room envelope testing with one of the two airlock doors as the boundary. The

licensee determined that the root cause was a deficient procedure in that

engineering information used to establish requirements for operation of airlock doors

was not periodically verified. Consequer.tir, during the performance of maintenance

on one airlock door, the second airlock door was unable to maintain the integrity of

the control room envelope. ,

The licensee's corrective actions included implementation of TS Amendment 115,

which allowed breaches of the control room envelope for a period not to exceed

7 days, repaired envelope door seals, performed acceptable pressurization testing of

the envelope, established criteria for operations to enter the applicable TS !imiting

condition for operation whenever an airlock door was inoperable, and revised plant

procedures to ensure TS entry prior to performing maintenance.

To improve the ability of the control room ventilation system to maintain the

envelope, the licensee developed Modification PC 8028, which will trip the reactor

auxiliary normal building ventilation on a toxic gas signal. Additionally, the licensee

initiated Modifications PC 8027 and SPEER 9601658, which will replace the control

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room envelope doors with better sealing doors. The inspectors determined that the

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implemented and planned corrective actions were effective for this violation. '

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E8.2 (Closed) Violation 50-382/9513-06: failure to establish design control measures.  :

This violation involved plant configuration control problems such as missing solenoid

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valve exhaust port covers and weep holes not drilled in the bottom of

environmentally-qualified terminal boxes. The inspectors verified the corrective

actions described in the licensee's response letter, dated May 19,1995, to be

reasonable and complete. No similar problems were identified.

E8.3 (Closed) Violation 50-382/9513-07: failure to identify conditions adverse to quality.  !

This violation involved the failure to initiate a CR for several material condition

deficiencies (i.e., a pipe cap was missing from the ta!l piece of  !

Valve EFW-MV-108A). The inspectors verified the corrective actions described in

the licensee's response letter, dated May 19,1995, to be reasonable and complete.

No similar problems were identified.

E8.4 (Closed) Violation 50-382/9521-01: failure to perform proper, detailed engineer.ing

analysis of solenoid-operated valves to establish and maintain equipment I

qualification. The inspectors verified the corrective actions described in the

licensee's response letter, dated February 14,1996, to be reasonable and complete. l

No similar problems were identified.

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E8.5 (Closed) Inspection Followuo item 50-382/9513-05: improperly installed terminal

box on an environmentally-qualified shutdown cooling heat exchanger resistance

temperature detector.

The inspectors reviewed and discussed the licensee's actions, documented in their

commitment tracking system (A 22451) related to this item, with an environmental

qualification engineer. The inspectors also reviewed the following environmental

qualification documents to evaluate the qualification of resistance temperature

detectors and associated cable:

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LPL-EQA-39.03, " Environmental Qualification Assessment for Rosemount

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Resistance Temperature Detectors," Revision 3; '

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LPL-EQA 39.04, " Environmental Qualification Assessment for Weed  !

Instrument Company Resistance Temperature Detectors," Revision 5;

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LPL-EQA-6.3C, " Environmental Qualification Assessment for Rockbestos

Radiation Resistant SR Cable (KF-550 Methyl Phenol Vinyl Silicone Rubber l

Insulation)," Revision 0; and,

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DC 3301 RTD Cable Replacement Report, dated July 15,1991.

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l The item was initially opened because a nonenvironmentally-qualified resistance l

l temperature detector junction box was found loose by an NRC inspector. During

review of this item, the inspectors noted that the environmentally-qualified

resistance temperature detectors had different maintenance requirements to ensure

adequate sealing. The inspectors also noted that the licensee had not identified,

during the review of this issue, any examples of environmentally-qualified resistance

temperature detector junction box covers being improperly sealed. The inspector

found no problems with the sealing of environmentally-qualified resistance

temperature detector junction boxes.

During the discussions with the licensee engineer, the inspectors noted that the

engineer was preparing a design change to replace the resistance temperature

detector cables inside containment. The inspectors learned that this was not the

first time that the cables were to be replaced. In 1991, the licensee replaced the

original Samuel Moore cables with Rockbestos Firewall SR high-temperature

instrumentation cable. The inspectors noted that the replacement was required

because the original cable had deteriorated as a result of being too close to reactor

coolant piping.

The inspectors noted that the replacement cable was qualified by similarity by the

manufacturer and accepted by the licensee. The similarity was based on the

construction of the signal conductors being the same. The similarity evaluation did

not consider the cable shields that were on the replacement cable. The shields

were not considered because their purpose was to reduce or dampen signal noise.

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The inspectors found the similarity evaluation to be acceptable.

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The inspectors noted that the licensee experienced noise problems in the instrument

loops after installation of the replacement cables, prior to returning the circuits to

operation. The noise was attributed to the shield wire being grounded in more than

one location, with a resulting potential difference causing circulating currents. The

licensee engineers attributed the cause of the multiple grounds to be due to the

porosity of the braided jacket and high humidity in the containment building. This

allowed a current path to the plant ground through the conduit system. In addition

to the path to the plant ground, the shield wires were connected to the instrument

bus ground, which was not common to the plant ground. The ground buses were

at different potentials, which caused the circulating currents and resultant noise.

To correct this issue, the inspectors noted that the shield wires were lifted at the

outboard containment penetration, breaking the circuit created t the grounded

shield wire inside containment. The inspectors found that the lii g of the shield

wires was an acceptable action to reduce the noise in the circui ,. Since three

elements were necessary to induce noise in a circuit (a source of electromagnetic

noise, a means of coupling of noise from the source, and a circuit sensitive to the

noise), the breaking of the circuit eliminated the problem.

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The inspectors did not identify any problems with the qualification documentation

for the resistance temperature elements or the cable. The documentation for these

items met the requirements of 10 CFR 40.49, " Environmental Qualification of

Electric Equipment important to Safety for Nuclear Power Plants."

The inspectors noted an additional potential mechanism for creating a ground path  ;

in the esb!es, which was damaging of each cable during installation. This  !

mechanism was not considered credible by the licensee since most of the circuits

experienced the noise problems.

The inspectors also noted that the licensee had developed a design change to

improve the existing design. In this change, the cable was to be replaced with a

similar cable that had an insulating jacket between the twisted, shielded pairs and

the braided jacket. This layer would provide protection from physical damage and

also provide a waterproof barrier, thereby eliminating the potential means of

coupling the noise to the circuit. The inspectors found that the design change was ,

an enhancement to the existing configuration. I

The licensee had adequate procedures to address the sealing of

environmentally-qualified resistance temperature detector junction boxes. The

existing configuration of the instrument cable and its shield wires was acceptable.

The proposed design change to the cable configuration was an enhancement.

IV. Plant Suooort

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R8 Miscellaneous RP issues (92904)

R8,1 (Closed) Violation 50-382/9610-03: failure of personnel to comply with health

physics warning signs. This violation involved the failure of personnel to properly i

control contaminated M&TE and the failure of personnel to comply with warning

signs prohibiting drinking in a radiologically controlled area.

In response to the control of M&TE, operations communicated expectations in the

daily instructions, provided training to operations on the requirements for the control

of contaminated equipment, placed new locks on the M&TE lockers, and required

that the shift supervisors be initially accountable for access to the lockers. The

inspectors performed periodic observations of the contents of the lockers and-

determined that contaminated items were properly labeled and contained. l

In response to the failure to adhere to signs prohibiting drinking in radiologically

controlled areas, the licensee removed the cooler from the area, provided training

during safety meetings to plant personnel, and developed a guidance directive on

the use of thirst quencher in radiologically controlled areas. The inspectors

reviewed Directive 96-2, " Outage Emergent items," and noted that the use of thirst

l quencher was to be established for heat stress controls and that individual

containers were to be placed in a secured ice chest labeled "FOR EMERGENCY USE

ONLY."

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The inspectors determined that the licensee's corrective actions were effective for

the examples involving this violation. i

P3 EP Procedures and Documentation

P3.1 Licensee Onshift Dose Assessment Capabilities (Tl 2515/134)

, a. Insoection Scoce

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l Using Temporary instruction 2515/134, the inspectors gathered information ,

regarding:

• Dose assessment commitment in emergency plan

l * Onshift dose assessment emergency plan implementing procedure .

! * Onshift dose assessment training

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l b. Observations and Findinas

On December 17,1996, the inspectors conducted an in-office review of the

emergency plan and implementing procedures to obtain the information requested

by the temporary instruction. The inspectors conducted a telephone interview with

the licensee on December 18,1996, to verify the results of the review. Based on

the documentation review and licensee interview, the inspectors determined that

the licensee had the capability to perform onshift dose assessments using real-time

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effluent monitor and meteorological data and that the commitment was described in

the emergency plan and implementing procedures.

c. Conclusion

The commitment to perform onshift dose assessments was described in the

! emergency plan and implementing procedures. Further evaluation of the information

obtained using the temporary instruction will be conducted by NRC Headquarters

personnel.

S1 Conduct of Security and Safeguards Activities

S1.1 litumination of Protected Area

a. Insoection Scone (71750)

On December 17, at 10:45 p.m., the inspectors performed a tour to determine the

adequacy of illumination in the protected area.

b. Observations and Findinas

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The inspectors observed that the quality of permanent and temporary lighting in the

protected area was substantially improved from previous tours performed in January

and May 1996 (NRC Inspection Reports 50-382/9522 and 50-382/9605).

Nevertheless, the inspectors observed inadequate illumination between the ,

insulators shack and the water treatment bui' ding.

The inspectors noted that the licensee had staged temporary lighting in the affected

area, but that the extension cord had been removed from the electrical outlet even

though a security placard was attached to the end of the cord which stated

" Temporary security lighting, do not remove." The inspectors informed the shift

security supervisors of the lighting discrepancy. The security supervisors toured the I

area with the inspectors and agreed that illumination was less than 0.2-footcandles '

and reenergized the temporary lighting. l

The inspectors questioned security to determine if the security patrol officer

identified the discrepancy on the evening tour. Security informed the inspectors

that the evening patrol officer noted the discrepancy and documented the poor

illumination on the security patrol log. However, the individual did not inform the

security shift supervisor of the discrepancy. The inspectors noted that the

supervisors were not aware of the discrepancy until informed by the NRC. The

failure to notify additional personr'el of the lighting deficiency is of concern because

compensatory measures may not have been effective in the event of an actual

security threat.

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Security Procedure PS-012-102, " Protective Lighting," Section 5.3.2, requires that,

in the event a protective lighting system deficiency or failure is observed vehen

lighting is needed, the reporting officer willimmediately notify the central alarm

station or the secondary alarm station. The inspectors determined that the security

patrol officer's failure to notify the central or secondary alarm station of the

deficiency is a violation of TS 6.8.1.a (50-382/9614-04). j

In response to the inspectors identification, security management implemented l

immediate corrective actions which included counseling the patrol officer and l

security shift supervisors, performing additional walkdowns of temporary lighting, i

and discussing the importance of temporary lighting with personnel who may I

deenergize temporary lighting during daylight hours. I

C. Conclusions

The inspectors identified a violation for the failure to notify the central or secondary l

alarm station of a lighting deficiency. The licensee has significantly improved the

quality of permanent and temporary lighting within the protected area.

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V. Manaaement Meetinas

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X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management

at the conclusion of the inspection on January 15,1997. The licensee ,

acknowledged the findings presented. >

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The inspectors asked the licensee whether any materials examined during the  !

! inspection should be considered proprietary. No proprietary information was l

l identified. i

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ATTACHMENT ,

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SUPPLEMENTAL INFORMATION

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

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R. G. Azzarello, Manager, Maintenance i

C. M. Dugger, General Manager, Plant Operations

! J. J. Fisicaro, Director, Nuclear Safety l

l T. J. Gaudet, Acting Manager, Licensing

l D. C. Matheny, Manager, Operations

, M. B. Sellman, Vice-President, Operations

l D. W. Vinci, Superintendent, System Engineering i

A. J. Wrape, Director, Design Engineering

I

INSPECTION PROCEDURES USED

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37551 Onsite Engineering )

61726 Surveillance Observations

62707 Maintenance Observations '

71707 Plant Operations

71750 Plant Support Activities

92901 Followup - Plant Operations *

92902 Followup - Maintenance

92903 Followup - Engineering

92904 Followup - Plant Support

Tl 2515/134 Licensee Onshift Dose Assessment Capabilities

ITEMS OPENED, CLOSED, AND DISCUSSED

Oper.ed

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50-382/9614-01 URI Review of the licensee's response to the water hammer u

events that occurred in the LPSI system (Section 02.1)

50-382/9614-02 VIO Inadequate procedure for testing the hydrogen analyzers ,

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(Section M1.3) l

t

50-382/9614-03 NCV Inadequate channel functional test for CPCs (Section M3.1) l

l

.

h

.. ,m. . . , - , , - - ~ , - , , . - - . - , r m . , , _ . -

_ _ _ . . _ . _ . _ . _ _ _ _ _ _ _ . _ _ _ _ _ . _ _ _ _ _ _ . _ _ . . _ . . . _ _ _ _ _ _ _ . . . _ _ _ _ _ _

1

~

1

.'

.

.

2-

50-382/9614-04 VIO Failure to follow security lighting reporting procedures

(Section S1.1)

.

l

Closed

!

50-382/9517-01 VIO Failure to acknowledge fire protection panel alarms (Section

08.2)

50-382/9605-02 VIO Control room personnel unaware of activities affec{ing

Emergency Diesel Generator A (Section 08.3)

50-382/9614-02 NCV Inadequate channel functional test for CPCs (Section M3.1)

-

50-382/94402-02 IFl Failure to follow an installation weld detail (Section M8.1)

50 382/9508-01 VIO Failure to follow procedures to ensure adequate storage of

.

loose items and correct usage of M&TE (Section M8.2)

50-382/9607-02 VIO Failure to perform adequate control room envelope testing

(Section E8.1)

50-382/9513-06 VIO Failure to establish design control measures (Section E8.2)

l

50-382/9513-07 VIO Failure to identify conditions adverse to quality (Section l

E8.3) 1

50-382/9521-01 VIO Failure to perform proper, detailed engineering analysis of

, solenoid-operated valves to establish and maintain

j equipment qualification (Section E8.4)

,

50-382/9513-05 IFl Improperly installed terminal box on an environmentally

qualified shutdown cooling heat exchanger resistance

'

temperature detector (Section E8.5)

l 50-382/9610-03 VIO Failure of personnel to comply with health physics warning

l signs (Section R8.1)

LIST OF ACRONYMS USED

ANO Arkansas Nuclear One

CFR Code of Federal Regulations

CR Condition Report

CPC Core Protection Calculator

! DN8R Departure from Nucleate Boiling Ratio

l DEAM Design Engineering Administrative Manual

- -. . - . --. - _- . - _ -

, _ _ _ _ _ . _ - - -. - -

.

l

.

. -

l

l

l

-3-

.

l

i

DRN Document Revision Notice j

!

HPSI High Pressure Safety injection j

IST Inservice Testing

LPSI Low Pressure Safety injection

M&TE Measuring & Test Equipment

NRC Nuclear Regulatory Commission

psig Pounds per Square Inch Gauge

PDR Pt.biic Document Room

QC Ouality Control

RP Radiation Protection

,

RWSP Refueling Water Storage Pool

SIT Safety injection Tanks

scfh Standard Cubic Feet per Hour

TS Technical Specifications

UFSAR Updated Final Safety Analysis Report

URI Unresolved item 4

'

UT Ultrasonic Testing

WA Work Authorization

.