ML20211P595

Trip Rept of 861210 Feedwater Line Rupture/Augmented Insp Re 861209 Event

ML20211P595
Person / Time
Site:	Surry
Issue date:	12/22/1986
From:	Caruso M Office of Nuclear Reactor Regulation
To:	Tondi D Office of Nuclear Reactor Regulation
Shared Package
ML20211P447	List: ML20211P443 ML20211P517 ML20211P595
References
FOIA-87-20 NUDOCS 8703020395
Download: ML20211P595 (20)

Text

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. /pH EICgDo UNITED STATES

.  !' - ' ' ^n NUCLEAR REGULATORY COMMISSION

{ $ WASHING TON,0. C. 20555

\*"**/

DEC 2 21986 MEMORANDUM FOR: Dominic Tondi, Chief PWR Assessment Branch FROM: Mark A. Caruso PWR Assessment Branch

SUBJECT:

TRIP REPORT: SURRY-2 FEEDWATER LINE RUPTURE /

AUGMENTED INSPECTION Enclosed is a draft of the Augmented Inspection Team's (AIT) report regarding the December 9,1986, Main Feedwater Pipe Rupture event at Surry Unit 2. I was assigned responsibility for and drafted Sections 3a, 3b, and 5d based on {

my inspections, interviews of operators, and review of available information onsite. It is my understanding, based on discussion with the AIT leader, that additional onsite support will not be required of me. However, some support will be needed to complete the final AIT report. A summary of my onsite activities is provided below.

I arrived onsite at approximately 1:30 P.M. on Decerrber 10, 1986. After going through security I was escorted to the Resident Inspector's office where I met the rest of the AIT. After being briefed on team activities and given my report section assignments, I was given a tour of the areas of Unit I and Unit 2 containing the main feedwater pumps and suction piping. The piping arrangements on the two units are identical and seeing Unit 1 provided a good frame of reference regarding conditions prior to the accident. Following this, I joined Region II team members in a twenty-minute training session covering site-specific security and radiological protection. This training supplemented generic training they had already taken as inspectors and permitted them free access to all but vital areas in the plant. For me to have obtained similar access would have required a full-day training session.

The AIT leader and I both felt this would be counterproductive based on the expectation that I would probably be onsite for only three or perhaps four days. Although this was the correct decision, not having free access was a hindrance for me in my investigations since an escort was required for me at all times and other members cf the AIT were busy pursuing their assignments.

At 5:00 P.M. I participated in a meeting with plant management in which the progress of their investigation was discussed along with plans for the next day. The AIT departed the site at 6:30 P.M. and returned at 7:00 A.H. the next morning.

In the morning briefing with the plant management I requested that the licensee provide me with an escort to walkdown the condensate and feedwater system piping. The purpose of this inspection was to look for signs of damage to pipe hangers, supports, and instrumentation which is characteristic of feedwater system waterhammer. An escort was provided and we covered the y/)9NO 07055NN ' on I gynce740

condensate and feedwater system piping between the condenser and main feedwater line penetratinns into containment. No damage was observed.

Following this inspection the escort and I climbeo the scaffolding in the Unit 2 turbine building for a close-up inspection of the damaged suction piping.

On Thursday afternoon,12/11, I joined Tom Peebles of Region II in interviews of three reactor operators on shift at the time of the accident. The results of these interviews helped establish a sequence of events. Following this we worked on developing a sequence of events. We then toured several areas of the plant, including the cable vault, cable penetration room, control room, and remote shutdown panel.

At 5:00 P.M. we met with plant management for the afternoon briefing. A report was given regarding the progress of metallurgical and stress analysis of the broken pipe. The licensee stated that sections of the broken pipe wall had thinned from a nominal thickness of .5 inch to between .06 and .1 inch, and that the rupture was believed to have been purely ductile. Results of their stress calculation indicated that rupture could be expected at 600 psi with a minimum wall thickness of .09 inch. The licensee also reported on results of tests on the failed MFW suction pressure transmitter and discussed plans for inspection of the "A" main feedwater pump discharge check valve.

The team arrived onsite Friday morning at 7:30 A.M. Following a meeting with plant management at 9:00, members of the team, including myself, witnessed the 7

opening of the "A" MFW pump discharge check valve and inspected the valve internals. Damage was noted and is described in the draft AIT report.

The remainder of the day was spent reviewing updated sequence of events information from the licensee and preparing the first draft of the AIT summary report. At 3:30 P.M. I was dismissed by the AIT leader and departed the site.

hY 4.W Mark A. Caruso PWR Assessrent Branch

Enclosure:

As stated cc: G. Holahan C. Rossi L. Rubenstein C. Patel

DRAFT PRELIMINARY PREDECISIONAL INFORMATION EXECUTIVE SUPNARY SURRY 2 PIPE RUPTURE EVENT DECEMBER 9, 1986

1. OVERVIEW 0F EVENT On December 9,1986, with both units operating at 100 percent power, a Unit 2 reactor trip followed by a main feedwater (MFW) line rupture occurred.

Unit 2 had completed a refueling outage and returned to full power operation on December 8, 1986.

A low-low S/G level in the C Steam Generator (S/G) caused a reactor trip and start of the two motor driven auxiliary feedwater pumps.

The control room operators noted the S/G code safety valves lifting and regulated S/G pressure through the atmospheric dump valves. Approximately 30 seconds after the trip, when the unit's electrical busses auto-transferred to offsite power, the operators noted that the A MFW pump was off. Five sec'onds later, a small steam release noise was heard followed by a very loud noise.

A shift supervisor who was in the turbine building noted a large steam break and went to the control room to advise the control room watch of the break. All secondary pumps were secured and the break isolated.

Water to the S/Gs was supplied by the auxiliary feedwater system.

The primary system responded nonnally to the loss of load transient Primary coolant temperature, primary pressure, and pressurizer level were stabilized in the desired band.

A notification of unusual event was declared at 1427 hours0.0165 days <br />0.396 hours <br />0.00236 weeks <br />5.429735e-4 months <br /> and was upgraded to an ALERT in order to ensure that station personnel accountability was effectively accomplished.

The 18 inch suction line to A main feedwater pump was found to have ruptured at the elbow where the line connects to the 24" condensate header.

In addition, station halon and cardox systems actuated because of water short circuiting control systems in the area. Control room habitability was a concern prior to initiating control room ventilation because doors were blocked open to allow better control room access without recognizing that carbon dioxide had been discharged in the areas above. The CO2 was apparently coming into the cont.ol room from the hallway. The emergency was tenninated at 1623 hours0.0188 days <br />0.451 hours <br />0.00268 weeks <br />6.175515e-4 months <br /> after accountability had been established.

2 Eight individuals were injured due to the steam and water. -Two of the injured subsequently died. Two of the injured were treated and released.

The unit was placed in cold shutdown at 0703 hours0.00814 days <br />0.195 hours <br />0.00116 weeks <br />2.674915e-4 months <br /> on December 10, 1986.

2. SEQUENCE OF EVENTS INI11AL PLANT CONDITIONS The only two major maintenance or surveillance evolutions in progress were:

the troubleshooting of a B train underfrequency relay for a Reactor Coolant Pump (RCP); and the troubleshooting of an auxiliary instrument air compressor. The first item had required the racking in and closing of the B Reactor Trip Bypass breaker. The A and B Reactor Trip breakers were still closed. The second item rcquired the shutdcwn of the running auxiliary l

instrument air compressor and the attempted start of the non-running auxiliary instrument air compressor. Instrument air was at 78 psig instead of 100 psig. Some minor construction activity was occurring in the vicinity of the Main Feedwater pumps.

The unit's data gathering computer (Prodac 250) was out of service, but reactor trip information was available from a sequence of events alarm printer and a newly installed Emergency Response Facility Computer (ERFC).

The alarm printer updates on a millisecond basis just prior to and following a reactor trip, but is limited in scope. The ERFC updates in fifteen second increments. Interviews with the Shift Supervisor and Control Room Operators were used to correlate times and to fill in gaps of the event.

PLANT CONDITIONS DURING THE EVENT 14:20:00-14:21:00 The first indication of a problem occurred at 2:20 PM when the Unit 2 control room received an annunciator alarm for the B steam generator (S/G) as feedwater flow was less than steam flow. This indication and the subsequent alarm on A S/G indicated that the C Main Steam Trip Valve (HSTV) had spuriously closed which caused increased steam flow in the other two lines.

14:21:(00-:15)

The closure cf the C MSTV caused Main Feedwater (MFW) pressure downstream of the C MFW flow control valve (FCV) to increase from 865 psig to 970 psig with A and B pressures of 845 and 835 psig. The other MSTVs closed shortly after due to the high steam flow in those lines caused by the continuing 100 percent demand of the main turbine.

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3 14:21:(:15 -:30)

A ~ 10w-low S/G level annunciator was received for C S/G. A reactor trip caused by low-low S/G 1evel in C S/G occurred at 14:21:22 (RT 00); this caused the start of the two motor driven auxiliary feedwater pumps and a main turbine trip. At RT +03 (3 seconds after RT) the control room

, operators (CRO) manually tripped the reactor. One control rod (M-10) indicated that it had inserted only to 35 steps.

At RT +04, the CR0 noted the S/G code safety valves lifting and took the S/G Power Operated Relief Valves (PORV) out of manual and began to regulate S/G pressure through this atmospheric dump mode.

Pressure downstream of the MFW FCVs decreased to 1008-1028 psig.

14:21(:30 -:45)

S/G pressuras were 1028, 1013, and 1055 psig. Low-low levels occurred in the A and B S/G which caused the steam inlet valve to the turbine driven auxiliary feedwater pump to open.

14:21(:45-14:22:00)

Following the reactor trip and with the primary temperature at 552 degrees F, the three MFW FCVs automatically closed. The MFW pump recirculation valves (FCV-FW-250A and 2508) for A and 8 pumps auto-opened as required.

Pressure downstream of the MFW FCVs increased on A to 1059 and decreased on B and C to 812 and 949 psig.

The unit's electrical busses auto-transferred to offsite power at RT +32, when the main generator auto-tripped on reverse current, as normal.

Immediately before and just after the transfer of the busses, the operators noted that the A MFW pump was off. Its recirculation valve stayed open but the B recirculation valve closed. Also, the A MFW pump breaker indication did not display its auto-off disagreement yellow light as it should have.

Five seconds later at RT +37, a small steam release was seen and heard in the vicinity of the first point heater steam-side safety relief, which is near the MFW pumps.

14:22(:00-15)

Pressure downstream of the MFW FCVs decreased to 445 psig, The MFW pump discharge pressure reached a peak of 1290 psig.

The noise of a small steam release was followed at approximately RT +42 by a very loud noise from the vicinity of the MFW pump suction piping.

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4 The primary system responded normally to the loss of load transient. Primary coolant temperature was stabilized at 520 degrees F and pressurizer level was recovered as it reached the low level setpoint. Primary pressure decreased from 2235 to 2015 psig following the reactor trip.

The probable time for the piping break was RT +40-45. The steam break was found to be in the piping at the 24 inch to 18 inch reducing tee toward the suction of the A MFW pump. The probable reason for the 8 MFW pump recirculation valve not being open with the B MFW pump running was that flow in that line was still in excess of the 2800 GPM required as a flow path existed backwards through the A MFW pump discharge check valve which was later found disabled.

14:22(:15-30)

An operations supervisor was in the turbine building looking at the construction activity around the MFW pure s. He noted the large steam break, went to the control room, and advised them of the break. The shift supervisor ordered that all secondary pumps be secured.

14:22(:30-45)

The B MFW pump was found auto-off with its yellow disagreement light on.

The high pressure heater drain pump was running and had to be turned off.

After all secondary pumps were secured, the noise stopped. The ERFC agreed with the operators on this time frame.

14:27 An Unusual Event was declared.

14:30 The CR0 changed normal suction of the charging pumps to the Refueling Water Storage Tank.

14:34 The CR0 secured B RCP to alleviate additional heat input to the primary.

14:40 An Alert was declared to assist in personnel accountability.

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5 14:45 Secured A RCP The Shift Supervisor noted that the condenser still had a vacuum and as there was no steam for the main turbine gland seal, opened the vacuum breake r.

15:06 The CR0 secured B auxiliary motor driven feedwater pump.

15:14 The CR0 began emergency boration to cold shutdown concentration.

15:39 The CR0 secured emergency boration.

16:25 One control rod (M-10) had indicated that it inserted only to 35 steps and now it was noted to indicate fully inserted.

3. EFFECTS OF FAILURE

a. Pipe Rupture i

The rupture of the 18" A main feedwater pump (MFW) suction pipe occurred on a 90 degree elbow at a point about one foot from where the suction pipe joins the condensate supply header. The point at which the

' break occurred relative to the main feedwater pump is indicated on l Figure 1, which is a picture of the identical undamaged Unit 1 piping l configuration. Figure 2 shows the rupture location from the condensate l supply header side. Figure 2 clearly indicates that the rupture was a catastrophic, 360 degree circumferential break. Figure 3 shows the 4

broken pipe from the MlW pump suction side,

b. Pipe Whip t

! Observation of the damaged "A" main feedwater pump (MFWP) suction l piping indicated significant movement of the piping following the rupture. The piping attached to the pump suction dropped and rotated away from the break point, pivoting on the elbow near the pump suction.

Although the piping came to rest against a portion of the "B" MFWP discharge piping it did not appear to have damaged it significantly.

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6 Inspection of the area following the event also revealed that one piece of suction piping had ripped off and was blown some distance from the break point. The piece was about 3' x 2' in size. It appears that the joint between the suction pipe and condensate supply header provided lateral support of the suction piping assembly including the suction isol6 tion valve. The loss of this support along with the weight distribution of the suction pipe assembly probably contributed to the pivot and rotation of the assembly,

c. Personnel Injury Those injured were eight contractor employees who were working in th<

general area, but not on the affected pipe itself. Six of these i individuals were hospitalized for treatment of severe burns. Three were evacuated directly from the site by helicopter, and three others were taken off site by ambulance. The other two, who were less severely injured, were treated at a clinic and released.

One of those hospitalized died the afternoon of the following day and another victim died two days after the accident. The others remained in serious to critical condition.

These contractor personnel were employed by Daniel Construction Company of Greenville, South Carolina, and by Insulation Services, Inc. of-Hopewell, Virginia. They were doing instrument line relocation and pipe insulatioh work.

d. Plant Cooldown The loss of the suction piping to the "A" MFW pump and subsequent steam release had no adverse effects on the plant cooldown. The MSTVs had closed as had the MFW FCVs before the pipe rupture. These actions isolated the S/Gs from the rupture. The normal cooldown mode for a MSTV closure event is steam release by the code safeties and continued feedwater flow from the auxiliary feedwater system.

4. METALLURGICAL ASPECTS The pipe fracture was 360 degrees and a section approximately 2'x4' adjacent to the fracture was blown out of the pipe. All fracture surfaces appear to be ductile in nature. The licensee has mapped the thickness of the blown out section. The thickness ranges from .120 inch to .330 inch. The drawing nominal thickness is .500 inch. The thinning appears to be relatively

, uniform except for some snell localized areas. The thinnest areas appear to l be small localized areas about 1/16 inch in thickness. The thin areas, appears to be caused by erosion /corrision with possibly some straining. It has not yet been determined how much each phenomenon contributed to the extent of the thinning. The licensee plans the following analysis to determine the metallurgical details of the failure:

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7 Task I: Fragment, "T" section and pipe section.

1. Perform detailed visual inspection of joined pieces.

2. Make chalk mark grid pattern for wall thickness measurements.

3. Photograph sections with grid marks.

4. Measure failed piece and compare dimensions to design circumference in several planes. Estimate swelling and wall loss due to swelling.

5. Perform microhardness tests across section from near weld and at apparent fracture initiation location.

Task II: Pipe downstream of fracture

1. Perform ultrasonic inspections of several locations.

2. Identify sections for further examination as required.

Task III: Destructive examination

1. Cut out sections adjacent to thinned wall and weld heat affected zone HAZ. Perform macro and micro evaluation of frac'ture surface.

2. Perform tensile tests of base material adjacent to weld location.

3. Cut section from weld locations and perform HAZ and base metal bend tests.

4. Perform destructive examination of specimens from Phase II as

required.

Preliminarily, the failure appears to be caused by overload because of the thinned pipe. The preliminary visual inspection of the failed parts indicates that the wall thinning could be caused by a corrosion / erosion machanism. Corrosion pitting does exist. The piping configuration and the corrosion pattern are similar to the steam generator "J tube" (except for much larger diameter) configuration and corrosion pattern that has previously been identified and well documented. The licensee analyses are detailed above in process for a better understanding of the failure mechanism.

I Portable micro examir.ation on the surface of the fragment indicates no

linearization of the grain structure at the surface of the metal. This l preliminary examination indicates that the pipe surface near the fracture I

has not been highly strained as would be expected with a high stress event such as a high pressure spike. Further examination will be required to confinn this.

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, The pipe in question is nominally 0.500" thick with a Code allowable value of 0.360". At a system pressure of 600 psi (approximately 150 psi above l

operating system pressure) and temperature of 370 degrees F preliminary

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calculations indicate that the pipe would burst at a wall thickness of approximately 0.090" and would yield at a wall thicknes of approximately 0.173". These results tend to indicate that with the pipe in its degraded condition, system pressure with pressure transients caused by nomal plant operation could rupture the pipe.

l S. ITEMS WHICH COULD HAVE CONTRIBUTED TO THE LIKELIHOOD OR SEVERITY OF THE EVENT

a. Equipment System Malfunctions 1

l These equipment systems have been examined:

(1) Plant Service Air / Instrument Air System (SA/IA) --- This system

, supplies air to the air-operated main steam trip valves. The system holds the valve discs open during nomal operation and shuts the valves with spring assist during a trip condition. The valves can also be shut manually by operator action. Before the event, this was the SA/IA status:

(a) SA/IA blue auxiliary compressor was running; turbine building compressors 3 in automatic, one off; condensate polisher air compressor floating on the SA/IA system; pressure indication as observed from the control room approximately 100 psig j .

(nomal range between 95 psig and 110 psig).

! (b) Just prior to the event, planned maintenance activities were l being perfomed on the SA/IA grey auxiliary compressor which consisted of installation of a new temperature sensing element. At this time, both blue and grey SA/IA compressors were secured to switch operations to the grey compressor.

i Both compressors were de-energized so that a transfer switch I could be positioned before the grey compressor was re-energized (the compressors have a single power source).

(c) Control room operators were aware of these operations and were adjusting air flow from the condensate polisher air compressor, as system pressure had decreased to approximately

( 85 psig.

l (d) At this time, the reactor tripped and the feedwater pipe l ruptured, control room operators observed that SA/IA system j pressure had not decreased below approximately 78 psig.

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9 (e) Discussions with control room operators indicate that operating experience has shown that SA/IA receiver pressure has dropped as low as 55 psig without a main steam trip valve closing. A pressure of approximate 40 psig at the main steam trip valve would cause valves to close. The overall operation of the SA/IA system, based on pressure indication at the time of the event, does not appear to have been a major contributor to the inadvertent closure of the "C" main steam trip valve.

(f) Operating procedures for the service air / instrument air system, main feedwater systems . condensate system and main >

steam system were reviewed. Discussions were held with operators to determine adherence to procedures, no problems were identified.

(2) "C" Main Steam Trip Valve (MSTV). The action which initiated this reactor trip and subsequent feedwater rupture was the inadvertent closing of the "C" MSTV. A review of the maintenance history }

indicated this valve was overhauled during the most recent refueling outage in November 1986. Following the overhaul, the valve position limit switch was adjusted and the valve was cold-cycled satisfactorily per Periodic Test 14.2 on November 27, 1986. On November 29, 1986, with Unit 2 in hot standby, the "C" MSTV was again cycled and the valve failed to open fully. The reactor operator generated a Work Order, 046251, which indicated that the "C" MSTV was binding and capable of only opening partially. However, on November 30, 1986, as documented in the Reactor Operator (RO) and Shift Supervisor logs "C" MSTV was cycled satisfactorily. There was no mention of any work being performed on the valve. Maintenance Work Order (MWO) 046251 still remains outstanding. The licensee has been unable to detennine if any corrective maintenance had been perfonned on "C" MSTV between November 29 and 30.

Another problem associated with the "C" MSTV discovered during the event, was the failure of the limit switch to sense a closed condition. A review of the Maintenance and test history did not identify any problems with the limit switch. The last time the valve was tested on November 30, 1986, the test results indicated satisfactory operation of the limit switch.

The licensee is making preparations to test the "C" NSTV and then disassemble the valve to determine the cause of the inadvertent closure and the failure of the limit switch to indicate valve closure.

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l (3) A Feedwater pump discharge check valve (No. 2-FW-127)

A review of the Maintenance history on this particular check valve revealed the valve was scheduled to be inspected in late 1984.

The licensee decided not to inspect the valve, based on a satisfactory inspection performed on the Unit 1 feed pump discharge system check valve and on the operational history of the valve. It should also be noted that during the startup prior to this event, the B main feed pump was operated with the "A" main feed pump secured. There was no mention of a problem with high feed pump suction pressures, and the A main feed pump was started successfully on December 5,1986. The licensee has disassembled 2-FW-127 and inspection of the internals showed the disk not be fully seated. One of the two hinge pins was missing and the valve seat displaced. The condition of the check valve at the time of the inspection would have allowed for flow in the reverse direction. The licensee is continuing to evaluate the conditon of the check valve and plans to disassemble the other Unit 2 and both Unit I feed pump discharge check valves.

(4) Feed Water System Maintenance History A review of recent feed water system maintenance history did not reveal any identified problems with the A or B main feed pump suction piping. The licensee has identified some problems with the feed water system such as pin hole leaks which were associated with erosion, but these problems were located in the feed water pump discharge recirculation piping. The licensee does not have a program to inspect the feedwater piping for thickness. However, the licensee does have a formal inspection program for ultrasonic inspection to determine thickness for the following portions of the secondary system:

- Turbine Exhaust Cross Under Piping

- 1st and 2nd Point Extraction System

- 3rd and 4th Point Extraction System

- Moisture Separation Drain Liner

- Moisture Separator Reheater Inlet Piping (5) Safety System Equipment Review A discussion with the Superintendent of Operations and a review of pertinent document, i.e., Plan of the Day, the tagging log, the reactor operator's log, the shift supervisor's log and the minimum equipment list for criticality and power operation check 4

' list--indicated that all safety-related equipment required to support unit ~ operation was operable. The only safety-related equipment problems indentified prior to the event were the inoperability of one of the three charging pumps (only twq are required to be operable by technical specifications); and one of

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11 the service water pumps, which was operable but listed in an alert condition. During the event, all safety systems responded as required such as the operation of the Reactor Protection System (RPS), the steam generator safety relief valves and the auxiliary feedwater system. The secondary power-operated relief valves (PORVs) were in the manual mode of operation. The operators took manual control of the secondary PORVs to control steam generator pressure, allowing the secondary relief valves to shut and to control the removal of decay heat in the primary plant.

The only equipment which did not respond as required was (1) a control rod (M-10) which indicated 35 steps for a short time following the reactor trip before indicating fully inserted; (2) the inadvertent initiation of the fire protection system discussed in Section 7; (3) failure of the "C" MSTV to indicate closed in the control room following closure; (4) failure of the security door card readers as discussed in Section 7; and (5) the inadvertent tripping of the "A" main feed pump with the failure of the pump breaker disagreement light to illuminate.

(b) Review of Maintenance Activities Being Performed Prior to the Event Discussion with licensee personnel and review of the maintenance activities being conducted prior to the event did not indicate any maintenance activities which would have contributed to the initiation or results of the event. Maintenance activities being conducted by the individuals who were injured was unrelated to the feed water system rupture and would not have contributed to the event.

(c) Chemistry - Corrosion Discussions with the Chemistry Supervisor indicated that no substantial chloride or oxygen contamination problems have been observed in the secondary side since replacement of the Unit 2 steam generators was completed in August 1980.

The licensee's metallurgist suggested that a preliminary evaluation appeared to indicate erosion /corrision of the piping similar to that observed on the licensee's S/G "J" tubes. This effect would be attributed to the piping being exposed to high temperature and pressure with turbulent flow patterns. Chloride and oxygen concentrations were found to be within required limits; and therefore, are not thought to be significant contributing factors to the pipe's wall thinning.

12 (d) Pressure Transient Inspection of the ruptured feed water piping indicates that although the pipe wall was degraded (i.e. thinned) it is likely that a loading contributed significantly to the initiation of the break. The force distribution necessary to produce the circumferential, guillotine type rupture which occurred is ~

currently being assessed by the licensee based on metallurgical examination and stress analysis. Reviews of PWR operating experience regarding waterhammer in feed water systems indicate that severe water hamer loads usually result in extreme damage to pipe hanger supports and instrumentation and are usually the result of feedwater control valve instability. The Surry tinit 2 feed water piping from the containment penetration back through the A main feedwater pump, heater drain pump and condensate pumps have been inspected by the team, and there is no indication of this type of damage anywhere but in the vicinity of the rupture.

Inspection by the licensee has also indicated no such damage. In addition to this, measurements of pressure between the steam generator and feed water control valves indicate there was no leakage from the steam generator back through the feed water system. A pressurization of the suction piping from the condensate supply header side seems unlikely. The A heater drain pump discharge pressure switch located just upstream of the break indicates that no high pressure condition occurred from that side. The licensee is confirming that the switch and associated circuits were in proper working order. The most probable cause of pressurization of the A Main feed water Pump (MFWP) suction, if a'ny, appears to be leakage frcm the discharge of the "B" pump to the A pump during the period that the A pump was not running and the B pump had not yet been tripped. This could have occurred from flow through the 18 inch cross tie between the A and B discharge lines, and leakage past the degraded "A" pump discharge check valve. There is a pressure measuring device located on the suction of the MFWPs; however, it failed due to water instrusion in the transmitter following the rupture leaving its as found reading unreliable.

6. LICENSEE'S RESPONSE TO THE EVENT

a. Operator Response 4

The response of the operators to the initial reactor trip and later pipe rupture was excellent. The Emergency Procedures were followed quickly and orderly. The steam break was isolated rapidly. The only item yet under review is the time frame and action associated with the one partially stuck control rod indication and the significance of this is minimal.

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b. Emergency Response l

The inspector discussed various aspects of the licensee's response to the feedwater pipe rupture with licensee employees. The first responder to the accident was a senior instrument technician who had been performing quarterly calibrations on security equipment. He

, responded to a Station Security call for first aid assistance to the

Unit 2 truck bay. Upon arrival, one injured employee was observed exiting the accident area. The technician escorted the individual to

' the high level intake structure and set up a triage area. Three additional personnel subsequently exited the accident area and were 1

provided first aid by the team that was present. The technician I

attempted to contact the Unit 2 Control Room using a security radio,

but was unsuccessful. The technician then proceeded to the Maintenance i Services area to call for assistance. Upon arrival, the technician

discovered two additional accident victims. The technician used the I plant page system to contact the Unit 1 Control Room, and instructed the operator to call in offsite medical support, including three tredical evacuation helicopters and two local rescue squads.

! The licensee prepared the victims for transport and moved them to i the licensee's heliport, located behind the training building.

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The three most seriously injured personnel were air evacuated to local burn units while three were transported by ambulance.

Licensee perso'nnel who were interviewed following the incident 1

have stated that the site's emergency team functioned extremely well and was well coordinated. Further, licensee representitives

, have stated that the Alert was declared so that a personnel

accountibility could be made because it was not known at the time l of the incident, how many personnel had been in the area when the

! feedwater pipe ruptured.

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c. Emergency Information Activities The accident spurred extensive interest from the media in the j insnediate plant area, throughtout Virginia, and nationwide.

Virginia Power issued its first press release slightly more than

. an hour after the declaration of the alert. This initial ,

j announcement was followed by several others later in the day and -

into the evening. Follow-up announcements were issued the next

few days. In accordance with the company emergency information

policy, Virginia Power began steps to open the near-site media center in the Surry, Virginia, Consnunity Center. Because the

, alert was canelled before the media center was fully operational, l reporters were briefed at the emergency operations facility at the site. Virginia Power also opened its main media center at company headquarters in Richmond and issued information from there for i

several days thereafter.

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14 i' The day after the accident press conferences were held at noon at the on-site training facility and at the Richmond media center.

An NRC public affairs officer uent to the site with the Augmented Inspection Team. He answered telephone media inquiries from the resident inspector's office and participated in two press conferences with Virginia Power. NRC also responded to inquiries received by the public affairs offices in the Region II Office and in Headquarters.

In addition to written announcements, news briefings, and answers to telephone inquiries, Virginia Power also made available to reporters, both videotapes and still pictures of the accident scene.

7. ASPECTS THAT MADE HANDLING THE EVENT MORE DIFFICULT

a. Security Barriers As a result of the line break, flooding occurred in Vital Battery Room

28. Since the card key reader controlling access to room 2B was part of a closed circuit, the resulting failure of the card reader caused

. all other card readers to fail, t The security force assigned an anned guard to rove the protected area

! to provide personnel access to any necessary vital areas. The card reader system failure existed from approximately 1426 hours0.0165 days <br />0.396 hours <br />0.00236 weeks <br />5.42593e-4 months <br /> to approximately 1449 hours0.0168 days <br />0.403 hours <br />0.0024 weeks <br />5.513445e-4 months <br />. After the water drained from the Room 2B card reader, the card key system was reactivated.

When it became apparent that the incident involved potentially severe injuries to plant personnel, the main security gate was opened and manned by two armed guards to allow the free movement of emergency rescue personnel and vehicles.

Since the incident occurred at security shift change, two full shifts

of guard force personnel were available for incident rsponse. It does not appear that any security activities or barriers impeded the licensee's ability to respond to the event or to remove the injured.

With the failure of the card reader system, access to the Unit 2 control room was lost. The licensee's security force responded and opened the two control room doors. An anned guard was posted at each door and acted as access control to the area. The security manager stated that the guards were only posted as a courtesy to operations, as the operations shift supervisor was responsible for control room access control. The guards were relieved when the card reader system was

! restored to working order. Other locked vital and non-vital areas were handled in similar fashion to provide access when needed. In these cases also, security was relieved when the card reader system was restored to operation.

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t 15 It has been noted by licensee management and by the inspectors that the security response capability was extremely good since two full shifts of guards were present. The fact that the event took place in a

' non-vital area, rather than in a vital area, facilitated the rapid .

movement of operations personnel. This aspect of security response capability should receive additional scrutiny to assure that security measures would not inhibit operational response to an event.

I b. Fire Protection Systems Actuations During the event, the following fire protection systems actuated--C02 System discharged into the Unit I and Unit 2 cable tray rooms. The i

discharge was due to spurious actuation from condensate entering the control panel located 'in the turbine building during the event.

--Halon System discharged into the Unit I and Unit 2 Emergency i Switchgear rooms. The discharge was due to spurious actuation from 1

condensate entering the control panel located in the turbine building during the event.

! --Sprinkler System discharged into the Turbine building on the Unit 2 side due to high temperature from the break and damage to sprinkler heads in the break vicinity.

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Actuation of fire protection systems required operations personnel to wear air packs' when entering the room discussed earlier. However, operators did conduct necessary tours to verify system and component operability.

i In order to assure that proper attention is given to the concern of fire protection system interactions, the following tasks will be

! undertaken by the licensee:

l Task I: Review design documents.

1 Task II: Document sequence of systems actuation l

Task III: Detemine physical location of fire protection zones and l panels - FB series.

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. Task IV: Determine physical location of MCCs, breakers and i other power supplies for the system in relationship to area of the feedwater line break. ,

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i Task V: Evaluate why the system actuated.

l Task VI: Detemine actions taken after event and evaluate the

{ adequacy of these actions.

] Task VII: Evaluate the interface of the system with other systems i

j Task VIII: Prepare conclusions, evaluations and  !

j recomendations

16 The inspector will follow licensee actions and evaluate conclusions and reconsnendations,

c. Other System Interactions There does not appear to have been other significant system interactions which impeded the safe shutdown of the plant. All shutdown systems responded as designed, and an orderly plant cooldown was accomplished.

8. CONSIDERATION OF SPUIDOWN OF UNIT 1 At 12:30 P.M. on December 19, licensee management decided to shutdown Surry Unit 1 and operation of the unit was placed on power rampdown at 5:30 P.M.

The unit was subsequently cooldown and placed on residual heat removal and is currently in a cold shutdown condition.

The decision to shut down the unit was based on preliminary findings resulting from the Unit 2 main feed pump suction pipe rupture. These findings indicated that there might have been significant thinning of the pipe wall due to a corrosion / erosion mechanism not fully understood at the time. The shutdown plan included inspections of selected Unit 1 feedwater piping to ascertain its condition with regard to pipe wall thinning.

Subsequent UT examination of the identical elbow that failed in Unit 2 revealed similar but not as severe pipe wall thinning.

The licensee will give priority to Unit 1 inspection after completion of the investigation to determine the root cause of the Unit 2 pipe rupture.

9. INVESTIGATION AND CORRECTIVE ACTIONS PLANNED The licensee had agreed to a quarantine of all equipment and systems which could be significant to the ongoing investigation of the event. Therefore, all activities undertaken with regard to restoration work or investigations were only done with the concurrence of the NRC team on site. Concurrence has been given for some turbine generator work on the turbine deck which is not relevent to the investigation. In addition, concurrence was given for the ongoing work listed below,

a. Ongoing The activities in the week following the event have centered around cleanup and restoration of the damaged area and the initial disassembly of certain equipment whose maloperation may have contributed to the event or provided infonnation during the event which may have been suspect.

17 (1) The following restoration activities are or have been ongoing in the damaged area:

(a) Removal of scaffolding that may have been damaged.

(b) Cleanup of asbestos material.  :

(c) Verification that no electrical hazards exist.

(d) Restoration of the Fire Protection Systems. ~

(2) The following equipment is or has been inspected:

(a) A main feed. pump suction gauge in the control room pegged at 1000 psi. The pressure transmitter associated with this gauge has been inspected to determine operability.

Subsequently, it was determined that the transmitter was 1/3 full of water and it appears that the electrical portion of the transmitter was not operable.

(b) A calibration check was performed on pressure cutoff switch for the High Pressure Heat Drain pump. This was done to determine if the section of line leading from the HP heater drain pump discharge to the condensate header had been pressurized to at least 600 psi. The switch was designed to cut off the pump if a 600 psi pressure was exceeded. The switch was calibrated and found to be operable indicating that a line pressure of greater than 600 >si was not present.

. The licensee is to initiate a 600 psig s1gnal to the switch to assure that the pump breaker will open.

(c) Disassembly of the 2"A" main feed pump discharge check valve to determine if operation of this valve could have contributed to a pressure spike in the suction line to the pump. This inspection revealed a missing hing pin and displacement of the valve seat - See Section 5(a 3).

(d) Disassembly of the 2"C' main steam trip valve to determine

which the valve closed during the early stage of the event.

i (3) Removal of the damaged pipe sections to a lay down area for future metallurgical and ultrasonic inspections,

b. Future The following activities are planned:

(1) Determine cause of Main Steam Trip Valve Closure (2) Unit 2 - UT the elbow at condensate header to 28 main feed pump suction pipe.

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18 (3) Unit 2 - continue metallurgical inspections and UT mapping of the damaged condensate / feed suction piping of 2A main feed system.

(4) Unit 1-UT inspection of selected elbows in condensate and main feed systems.

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l YtmonwrA Ex.scr 1C AND Powan COMPANY

, Ricnwoma,VapotwrA sonst December 23, 1986

w. L. svmwes Vsco Paseroert Nocteam opesatione i

Mr. Harold R. Denton, Director Serial No. 86-8208 Office of Nuclear Reactor Regulation No/JDH Attna Mr. Lester 5. Rubenstein, Director Docket Nos. 50-338 FWR Froject Directorate No. 2 30-339 U. 8. Nuclear Regulatory Commission License Nos. NFT-4 Washington, D.C. 20535 NFF-7 Gentlement VJECINIA ELECTRIC AND F0VER COMPANY WORTM ANNA _ POWER STATIOK WITS AED L SURAY UNIT 2 FREDWATER FUMP BUC"IOf LhWE Bn"? EVENT I wish tc assure you of the seriousness with which Virginia Electric and Power Company views the December 9,1986 event at Surry Fower Station Unit 2. We have taken, and will continue to take, assressive actions to assure that the lessons learned from this event are fully appreciated, that appropriate and timely corrective actions are implemented, and that information of value to the nuclear industry is quickly disseminated. As you say know, we have already contacted many utilities regarding our preliminary findings.

Specifically, we intend to closely examine, evaluate, and implement as appropriates i The recommendations of our incident response organisation which is

, currently examining the event. Our investigations will continue until we are satisfied that we have identified the caue9e of the event and the subsequent failure path leading to the pipe rupture.

The recoseendations of the NRC augmented inepection team which is also examining the event. Although their report is not yet published, we will address their recommendations in a positive fashion. Our implementation of any NRC recommendations will be discussed with you prior to implementing any action.

The generic reconsendations that may artes as a result of subsequent  ;

NRC revieve of the event. l i, J'01/l - $ 1* *2 O

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In addition, we hope to coordinate a meeting with b'RC Region II staff during mid-January to present our detailed findings of the event and results of pipe inspections up to that time.

If you have any questions on this matter, please contact me.

Very truly yours,

,$b 1$$h($4P35W$hby g;qr,W.L. Stewart ccr Dr. J. Nelson Grace Regional Administrator NRC Region II Hr. Leon B. Engle NRC North Anna Project Manager PWR Project Directorate No. 2 Division of PWR Licensing-A Hr. J. L. Caldwell NRC Senior Resident Inspector North Anna Power Station 9

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VIRGINTA ELECTRIC AND PowEn CoxrAny Rien w ow n, Vino ix Aanas

. December 23, 1986 y 3,, ,, ,

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a Mr. Harold R. Denton, Director Serial No.86-843 Office of Nuclear Reactor Regulation N0/JDH vlh Attn Nr. Laster 5. Rubenstein Director Docket Nos. 50-280 PWR Project Directorate No. 2 50-281 Division of PWR Licensing-A 1,1 cense Nos. NPF-4 U. S. Nuclear Regulatory Cossaission NPT-7 Washington, D. C. 20555 Centlement VIRGINIA ELECTRIC AND POWER COMPAFT SUR3Y POWER STATIOR UNITS 1 AND 2 IMPACT OF DECEMBER 9.1956 stTRRY _2 EYINT ON -

40 TgAR OPERATING LICENSE AisuiDWiiii REQUEST On December 19, 1986, you requested that we provide information regarding the December 9, 1986 feedvater pump suction ifne rupture event at surry Unit 2 and evaluate its impact on our licanoa amendment request (August 22, 1986, as supplemented) to extend the Surry license period to forty years. Our response is provided below.

Question:

What safety significance does the recent pipe failure ever.t at Surry 2 due to corrosion / erosion have on the license extension request?

,Responset Ve have evaluated the safety significance of the December 9, 1986 event at Surry Unit 2 and have concluded that the event has no impact on our surry iteense amendment request. The basis for our conclusion is stated below.

Current Technical Specifications and Inservice Inspection Prograno se required by 10 CTR 50.55a for Surry require periodic inspection of safety-related nystens and components and provide a high degraa of assurance that any nignificant degradation of safety related piping would be promptly identified and corrected. These programs would continue during the extended license period. In addition, the majority of safety-related pipint is stainless steel rather than carbon sceal and is not readily susceptible to the erosion / corrosion phenomena.

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toss of mormal feedwater events have been analyzed for Surry and the recent Surry,2 event was bounded by those analyses. It is not expected that any piping nodifications that might be implemented as a result of this incident would affect those analyses. This would be verified as part of the design change review which includes assessments of impacts on accident analyses. These actions would be taken independent of our license amendment request. Question: Is Virginia Electric and Power Company taking any special actions because of the incident that bears on the proposed license amendment request for Surry? Re_esonee t periodic inspection of certain non-eafety related systems and components are covered by existing programs at to assure prompt identification and appropriate corrective actions for significant degradation. As a result of the Surry incident, the scope of these programs will be expanded to include portions of

                ' systems and piping susceptible to the erosion-corrosion phenomena.

This action is being implemented independent of our forty year licensa amendment request and has no direct bearing on it. Novaver, these inspection programs, implemented during the current license period would be continued during the extended license period and the same benefit from the programs would be derived during the additional years of operation. Verytyuly ours. OA W. L. ivart

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