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Valero (26003), Norco

Releases of Volatile Organic Compounds (VOCs)

LDEQ Accident Number
Accident Date
Point Source(s) Notes Amount of Release
82697

2005-10-01
Wet Gas Compressor
Cause: Wet gas compressor tripped due to sudden loss of lube oil pressure. Gas processed by compressor was directed to flare.

Followup: Yes

Notes: Still under investigation - no procedures or preventative measures identified.
37.0 pounds
82120

2005-09-12
Flare 1 EIQ 15-77; Flare 2 EIQ 12-81
Cause: Loss of power, control valves failed. Power interruption caused by 3rd party electricity provider. Battery back up system damaged when it received a power surge during restart of refinery after Hurricane Katrina.

Followup: Yes

Notes: reduced feed rates to our West Plant
40.0 pounds
78904

2005-05-07
Flare 1 EIQ 15-77; Flare 2 EIQ 12-81
Cause: During startup of unit, one wet gas compressor failed to start as expected due to unanticipated electrical problems. Process gases normally routed through this compressor were diverted to the flare.

Followup: No Information Provided

Notes: Compressor repaired as quickly as possible.Air filter clogged with debris. Inspection of air filter has been added to preventative maintenance schedule.
723.0 pounds
78487 ; 78475 ; 78488

2005-04-23
Flare 1 EIQ 15-77
Cause: MSCCU wet gas compressors tripped due to problems with common lube oil system.

Followup: Yes

Notes: Reduced feed rate to MSCCU. Issue involves wet gas compressor as seen before. Follow up report sent on June 6, 2005 with remedies: redesign of the nitrogen regulator and replacement of the pressure controller on the lube oil system
223.0 pounds
78141

2005-04-10
Flare 1 EIQ 15-77
Cause: Compressor tripped due to low lube oil differntial pressure on the 2nd stage of the compressor. Root cause investigation not complete at the time

Followup:

Notes: Total pounds emitted from both flares. Remedial actions of reducing feed rate and reducing the reaction temperature so that the offgas to the flare can be reduced. No procedures or preventive measures identified at that time.
521.6 pounds
76469

2005-01-25
Heater 1501 B
Cause: Tube leak at heater H-1501-B

Followup: No

Notes: Courtesy notice. Shutting down unit.
76182

2005-01-13
No Information Given
Cause: Loss of steam caused by a lack of water from the boiler water feed pumps. Pump suctions were plugged. Yarway valves were worn and were by passing more water to the pump suction drum than expected. Both resulting in low water flow to the boilers.

Followup: Yes

Notes: NO original incident report in this file. Instituted additional procedures to require personnel to measure pump suction pressure during routine rounds to determine whether or not the pump suction is plugged. Added procedures to monitor the discharge pressure of the Yarway valves to ensure proper operation. INstalled an alarm ont he control valve to indicate for low water discharge. conditions. There was
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
19.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
22.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
31.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
6.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
7.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
5.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
16.0 pounds
100919

2007-11-09
EQT 013 and EQT 007
EQT 013 and EQT 007 (Flares #1, 2)
Cause: The Wet Gas Compressor tripped on low oil pressure.

Followup: Yes

Notes: The incident involved releases on two separate days, 11/09/07 and 11/12/07, but were assigned the same incident Report # by SPOC.
47.0 pounds
97330

2007-06-24
EQT 013 and EQT 007; Flares 1 and 2
Cause: The wet Gas Compressor tripped on low lube oil pressure. This caused the Coker off gas to go to the flare. The cause of this incident is under investigation.

Followup: Yes

Notes: Emissions were minimized by immediately restarting the Wet Gas Compressor.
14.0 pounds
94320

2007-03-01
line on c 3/4, LPG area
Cause: While loading a line on the c 3/4 in the LPG area, they found a pinhole leak.

Followup: No

Notes: They put steam on the line (of c 3/4) for the pressure differential.
93388

2007-01-19
Coker Unit heat exchange
Cause: Reason not stated.

Followup: No

Notes: Strange letter: Letter states the leak began on Saturday, January 20; however it also states that Ms. Dillon of the St. Charles refinery notified the LA State Police and the NRC of the leak on Friday, January 19. Also, the sample analysis taken on Friday indicated "an unusually large amount of H2S and Total VOCs from the exchanger. However, we determined that the units associated with the lab data were incorrectly reported," and they provide the quantities listed at left. This notification was mto be considered at a courtesy since no quantities exceeded the reportable amounts.
18.0 pounds
109755

2008-10-01
Flares 1 and 2
Cause: Hot Separator develops crack allowing material and gases to release.

Followup: No

Notes: Emissions minimized with a controlled shutdown of the unit. Firewater sprayed on to control vapors and mitigate inflammation. Oil absorbent booms deployed. Water collected by vacuum truck from drainage routes.
106285

2008-06-09
Flares 1 and 2
Cause: MCCU was shut down so that a pinhole leak on the Millisecond Cat Cracker unit could be repaired

Followup: Yes

Notes: A plug was installed to minimize the leak.
105908

2008-05-27
71A Refrigerant Condenser
Cause: VOC leak from process unit in cooling tower

Followup: No

Notes: Condenser was isolated and is in the process to be repaired [sic]. Follow-up letter states that emissions were BRQ.
3,312.0 pounds
103521

2008-02-29
Flare
Cause: while initiating corrective actions for another incident the WGC tripped.

Followup: No

Notes: Emissions minimized by immediately restarting WGC.
81.0 pounds
102905

2008-02-08
East Plant
Cause: East Plant coming down for a scheduled maintenance turnaround

Followup: No

Notes: Courtesy notification of scheduled turnaround
102201

2008-01-10
Flare Gas Recovery Compressor
Cause: Flare Gas Recovery Compressor tripped

Followup: No

Notes: Letter states that emission were BRQ.
1.0 pounds
102102

2008-01-06
Coker Wet Gas Compressor
Flares 1 and 2
Cause: failure of WGC

Followup: No

Notes: DEQ report states that there have been many WGC failures, enough that they have made repeated calls to the facility urging them to repair the unit to prevent recurrence of such events. According to report, Valero has repaired the WGC.
72.0 pounds
102086

2008-01-03
Flares 1 and 2
Cause: Guardian over speed device malfunction causes WGC to trip

Followup: No

Notes: Emissions minimized by immediately restarting WGC. A series of follow-up reports reveal that Valero did not know age or maintenance history of WGC upon purchase of facility from Orion. Valero has now replaced major components of WGC and plans to replacethe guardian over speed device next.
61.0 pounds
120151

2009-12-13
tank T-04-32
Cause: Due to heavy rains falling onto tank T-04-32 (sour water tank, EQT 099), the tank's external floating roof became imbalanced and began to tilt. This allowed hydrocarbon material to seep onto the rooftop.

Followup: No

Notes: A vapor suppressing foam blanket was applied to reduce the evaporation of hydrocarbons.
21,522.0 pounds
116428

2009-07-12
#3 Debutanizer Reflux pump
Cause: At approximately 1:15 operators noticed that the #3 Debutanizer Reflux pump seal had failed and was releasing process gases ti the atmosphere. Seal failure was caused by a failure in the pump's thrust bearing.

Followup: Yes

Notes: Deluge water was used to contain the vapors and reduce the risk of fire. The malfunctioning pump was isolated and shut down. A redundant backup pump was started to avoid unit shutdown. Reflux pump thrust bearings will be replaced from 40 degree contact bearings to 15 degree contact bearings.
4,988.0 pounds
115395

2009-07-02
Flares 1, Flare 2
Cause: While performing a preventative maintenance check. While checking voltage output levels on the power supplies in the control cabinets an arc was created that shut down both power supply #1 an #2. The loss of both power supplies caused the redundant controllers to power down, which shutdown the Coker Wet Gas Compressor sending material to the flare.

Followup: Yes

Notes: Wet gas compressor was immediately restarted
40.4 pounds
115515

2009-06-09
Fire
Flare 1 and 2
Cause: High temperature sulfide corrosion caused a pipe in vacuum tower bottom service to fail. The leak combusted, process units were upset, and ultimately shut down. Shutdown caused emission from flare.

Followup: Yes

Notes: After the fire was discovered, crude/vacuum/coker processes were suhut down and the units were depressurized to flare.
48.0 pounds
128357

2010-12-27
FLARE: flare #1 & #2
Cause: Wet gas compressor (WGC) in the delayed coking unit malfunctioned resulting in SO2 emissions to Flares #1 and #2. A level indicator on the coker tower HCGO tray malfunctioned. FLARE.

Followup: Yes

Notes: RQ. Reportable quantities for sulfur dioxide were exceeded. See Root Cause Analysis for more information. DLEQ report, Refinery letter, and follow-up letter all included in file.
80.0 pounds
123734

2010-05-25
FLARE: MSCCU
Cause: Small hole in Milli-Second Catalytic Cracking Unit (MSCCU)--had to flare when shutting down for repair. FLARE.

Followup: No

Notes: BRQ. Refinery letter states that no reportable quantities were exceeded. No information given regarding remedial actions.
2,010.0 pounds
122114

2010-03-14
pump connected to tank 80-1
Cause: Portable diesel-powered transfer pump caught fire. Releases include Acetaldehyde 0.0284 lbs and Acrolein 0.0034 lbs. FIRE.

Followup: No

Notes: ERT extinguished fire in 20 mins.
0.2 pounds
135435

2011-11-19
FCCU
FFCU
Cause: On 11/19/11, Valero was starting up the Fluid Catalytic Cracking Unit (FCCU) after a power failure tripped the unit. At approximately 2:30 am while start up was in progress, Valero made a notification of startup flaring and that the roof and seals of Tank 67-1 had been damaged resulting in elevated levels of Hydrogen sulfide. Benzene and VOCs being emitted. As a result of the damage of Tank 67-1, hydrogen sulfide and total VOC's including benzene and propylene may have exceeded their respected reportable quantities. Emission calculations for this event are pending and will be included in a subsequent report. Limits for opacity were exceeded in these flares #1 and #2. Liquid vapor pressure on T-67-1 exceeded 11.1 psi.

Followup: No

Notes: Emissions from the refinery flares and Tank 67-1 were lost to the atmosphere and dispersed. Tank Farm Operators moved quickly to inspect Tank 67-1 and activated vapor suppression safety equipment. Operational moves were made to isolate the tank from service and air monitoring was conducted in the tank farm, at the facility fence line, and west of the facility. Supression foam was placed on the tank roof to suppress any vapors and the tank contents were mixed with lower vapor pressure material in order to reduce the overall vapor pressure of the stored liquid. Utility Operators maximized steam to the refinery flares to mitigate visible emissions resulting from the ongoing FCCU startup. NO Ldeq, SPOC report. No follow up.
134352

2011-10-04
Cooling Tower 800
Cause: While conducting routine El Paso Method cooling tower monitoring on 10/4/11, Valero detected elevated hydrocarbon levels at Cooling Tower-800 (CT-800) but these were not above reportable quantity. They began manually sampling coolers and heat exchangers serviced by CT-800 in an attempt to identify the source. On 10/6/11 a Gasoline Desulfurization Unit (GDU) exchanger showed indications of a leak and it was isolated and removed from service. However, conditions did not improve and continued sampling revealed a leaking exchanger in the Fluid Catalytic Cracking Unit (FCCU). Once removed from service on 10/6/11 conditions in CT-800 returned to normal. Valero estimated that the RQ's for benzene and VOC's were exceeded on 10/6/11 based upon El Paso monitoring results collected that day. The leading exchanger bundle was inspected and results suggest the leak was due to low cooling water velocity and under deposit corrosion.

Followup: Yes

Notes: VOCs were released from CT-800 and dispersed. The heat exchangers believed to be leaking were isolated from service. Sampling was conducted at the cooling tower and at exchangers until emission rates returned to normal. The following corrective actions were identified to prevent recurrence of this event: (1) Re-analyze past exchanger inspection results and confirm recommendations. (2)Increase the frequency of calibration of residual chlorine analyzers on all cooling towers. (3) Improve exchanger leak identification training and internal reporting. The weather during this incident was a sunny, 81 degrees, with a wind speed of 7 mph.
37,495.0 pounds
133142

2011-08-17
Coker "A" drum
Cause: Process vapors were released through a crack in the Coker "A" drum, the integrity of which is included as part of the preventative maintenance program. Therefore, this event qualifies as a reasonably unforeseeable upset. The crack occurred at an elevated altitude, and process vapors were completely dispersed near the vicinity of the Coker structure where the release occurred. The refinery estimated that 85% of the release was steam, since the product was well into the quenching portion of the process.

Followup: Yes

Notes: Emissions from the drum crack escaped to the atmosphere and were dispersed. The refinery shifted from 4-drum to 3-drum operation and reduced charge rates as appropriate. As of 10/14/11, the cracked drum has been repaired and returned to service. New engineering data indicates that designs that include a thicker sidewall will provide superior performance and minimize any vessel cracking. The refinery has purchased these drums, and they are on schedule for installation (replacing the old drums) in the first quarter of 2012. The refinery also has a program of routine non-destructive testing that attempts to predict potential problem areas in these drums.
564.0 pounds
131415

2011-05-20
1600 TOX and Flares 1 and 2
30, 3700, and1600 Unit Thermal Oxiders, Flares 1 and 2
Flares 1 and 2
Cause: Due to multiple equipment high levels during startup of the Gasoline Desulfurizing Unit (GDU), hydrocarbons were introduced into the refinery's sulfur dioxide removal system and to the Sulfur Recovery Units (SRU) feeds resulting in unit upsets. Sulfur dioxide levels at the 1600, 3700 and 30 Unit Thermal Oxidizers were elevated from 3:24 pm on 5/20/11 until 8:00 am on 5/21/11. This caused smoking from the 1600 TOX stack from approximately 3:55 until 4:10 and the unit was shut down during this time. The 3700 and 30 Unit TOXs were also shutdown at approximately 3:40 and 4:13 respectively. Additionally, these process upsets also impacted the refinery's fluid catalytic cracking unit resulting in flaring for portions of this incident.

Followup: Yes

Notes: Valero did not show their limit for SO2, CO, NOx, PM, and VOC in the Thermal Oxidizer and flarecap. No limit was shown for Benzene in the Thermal Oxidizer. No limit was shown for H2S and Propylene in the flarecap. Accurate estimates could not be made. All values are below the total emitted and may be grossly deflated. During the event Valero received an odor complaint and took action to prevent and minimize any public nuisance. Field monitoring did not reveal any detectable quantities of VOCs or sulfur dioxide. Operational moves were made to the sulfur recover plants to shutdown the thermal oxidizers safely. Operators maximized steam to the refinery flares to mitigate visible emissions. During the incident fence-line monitoring was conducted by Valero and there were no detectable concentrations found. The following corrective actions were identified to prevent recurrence of this incident: (1) Modify the startup procedure for the GDU to ensure a shift supervisor monitors the unit radio channel (2) Include in the SRU standing orders that amine upsets be communicated to the shift supervisor and the shift superintendent (3) Modify GDU SOP's to amplify actions required for the amine system (4) Configure a separate console to receive all GDU alarms (5) Implement alarm management to allow high priority alarms to be flagged (6) Consider installing an auto shut off on the amine absorbers bottoms plant wide (7) Consider installing a bypass on the feed to untreated gasoline storage to improve feed control to the GDU during start up (8) Train the SRU operators on the rich DEA flash drum weir configurations. The hydrogen sulfide and sulfur dioxide permitted rates and reportable quantities were exceeded. There were released of nitric oxide, benzene, and VOCs released above reportable quantities. Opacity and visible emission limits were exceeded for flares 1 and 2 and the GRP007 SRU/TOCAP-SRU TO/CAP. The SRU sulfur dioxode concentration limit (250 ppm/ 12 h) for 30 and 1600 Unit TOXs and the EP and WP Fuel Gas hydrogen sulfide (162 ppm/3 h) were also exceeded.
7,334.2 pounds
144411

2012-11-05
Flare 1 and 2
Cause: The wet gas compressor in the delayed coking unit had malfunctioned.

Followup: Yes

Notes: The maximum hourly permitted emissions for hydrogen sulfide and sulfur dioxide exceeded the maximum hourly permitted emissions. Gas from the coker was combusted in Flare 1 and Flare 2. The resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. The incident will be communicated to all affected personnel. The XY-53325 A and B solenoids as well as the XY-53325A relay will be replaced during the text outage. Wiring in the compressor control cabinet will be upgraded to separate critical wiring from general purpose wiring.
1.0 pounds
142968

2012-09-13
Wet Gas Compressor
Cause: The Wet Gas Compressor (WGC) in the delayed coking unit had malfunctioned resulting in excess SO2 emissions at Flares 1 and 2. The WGC malfunction was caused by a loss of power to the Bentley Nevada (B/N) Control Panel. The B/N Panel is powered by two separate supply feeders, each having a breaker. Maintenance personnel who were investigating the WGC malfunction found that both power source breakers to the B/N panel had tripped causing the WGC to lose power, which resulted in flaring. It could not be determined if both breakers tripped at the same time or if one had failed earlier eliminating the redundancy. Maintenance personnel could not find any issues inside the B/N panel so they reset the breakers and restored the power to the panel. The WGC compressor was reset and restarted without further issue. This event is considered reasonably unforeseeable and therefore qualifies as an "upset."

Followup: Yes

Notes: Gas from the coker was combusted in Flare 1 and 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. In the future, the facility will communicate the incident to all affected personnel. They will install a power monitoring system that will trigger an alarm on the Distributed Control System (DCS) if one of the power system fails. They will also install breakers separated by a physical gap on the power supply. Finally, they will review other Bentley Nevada systems in the refinery for similar issues. The reportable quantity for SO2 was exceeded.
4.0 pounds
141595

2012-07-27
wet gas compressor
Cause: The wet gas compressor in the delayed coking unit malfunctioned resulting in excess H2S and SO2 emissions at Flares 1 and 2.

Followup: Yes

Notes: On the day of the incident, the steam control valve that regulated the turbine speed for the Coker WGC to account for increased gas flow rates due to an upstream process upset. When this upset was corrected, the gas flow to the WGC decreased and operators began closing the steam control valve for the steam turbine to reduce the speed of the WGC due to this lower gas flow. However, the steam control valve did not provide adequate response and did not result in a change in turbine speed. The WGC ultimately shutdown when the turbine reached its protective overspeed trip point and stopped all steam flow to the turbine. This happened very quickly and no further adjustments to the steam control valve before the turbine tripped. Emissions were minimized by restarting the wet gas compressor. This incident will be communicated to all affected personnel. The facility will install a control clamp at 80% on the steam control valve output to prevent a delayed control response due a dead band on the valve. A team will also be created from operations, controls, process, and reliability to monitor and record events in the Trilogger and review with the process control design team on a biweekly basis to control performance and tune as necessary. There is a discrepancy regarding the incident date. The subject lists the incident date as 07/27/2012, while the written notification states that it occurred on June 27, 2012.
2.0 pounds
140457

2012-06-13
wet gas compressor
Cause: The Wet Gas Compressor malfunctioned when operators were warming Coke Drum D. Shortly after switching to Coke Drum D, pressure on the unit spiked and the Fractionator overhead became overloaded. The temperature increased 20 degrees and caused the Interstage drum to become overwhelmed with condensing liquid. The compressor tripped on high interstage level resulting in flaring.

Followup: Yes

Notes: As a result of this incident, the maximum hourly combined permitted emissions for H2S and SO2 were exceeded as well as the reportable quantity. Emissions were minimized by restarting the wet gas compressor. The facility will now hold an operations stand down with each shift to review the incident and stress the importance of following all standard operating procedures. The facility is also adding a line to the console check sheet to verify that the tap water is blocked in before warming up drums prior to switching drums.
23.0 pounds
140250

2012-06-05
wet gas compressor
Cause: The wet gas compressor in the delayed coking unit malfunctioned resulting in excess H2S and SO2 emissions at Flares 1 and 2.

Followup: No

Notes: Gas from the coker was combusted in flare 1 and flare 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. The incident is still under investigation. No procedures or preventative measures have been identified at this time.
20.0 pounds
140047

2012-05-26
wet gas compressor
Cause: The wet gas compressor in the delayed coking unit had malfunctioned resulting in excess SO2 emissions at flares 1 and 2.

Followup: Yes

Notes: Gas from coker was combusted in Flare 1 and Flare 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. This incident is still under investigation. No procedures or preventative measures have been identified at this time. A "30 day follow up report" was submitted on February 28, 2013 citing that the root cause failure analysis report had been submitted for the incident. The document only lists 3 actions Valero plans on taking: "1. We will communicate this incident to all affected personnel. 2. Operations will implement a guidance document to reduce set points by 15 degrees Fahrenheit on loss of LCO charge heater. 3. Improve cracking beds operation stability by limiting the temperature delta. Add a high priority alarm to the DCS." The February 28th letter does not provide the root cause of the accident.
25.0 pounds
139226

2012-04-30
Wet gas compressor
Cause: The Wet Gas Compressor in the delayed coking unit at Valero St. Charles Refinery malfunctioned resulting in excess SO2 emissions at flares 1 and 2.

Followup:

Notes: Refinery fuel gas was combusted in Flare 1 and Flare 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. This incident is still under investigation. No procedures or preventative measures have been identified at this time.
21.0 pounds
152289

2013-11-11
Flare 1
Cause: On November 11, 2013, the Valero St. Charles Refinery experienced flared while making repairs on the Coker Jet Pump, which supplies water to the coke drums during the coke cutting process. Portable pumps were installed during the repairs but kept tripping due to vibration issues. Therefore, we cut feed to the coker and the heaters were put on circulation. The decreased fee into the Coker Unit from the Vacuum Unit caused the Wet Gas Compressor (WGC) to trip, which caused flaring. When the WGC tripped, pressure started to build up on the Vacuum Jet Receiver. To prevent the Vacuum Jet Receiver pump from tripping and causing a loss of vacuum in the vacuum distillation column, the backpressure on the jet receiver was relieved to the flare until the WGC stabilized. The pressure control valve on the vacuum jet receiver was open to the flare for approximately one hour, but intermittent flaring ensued until the rates in the coker unit could be increased to provide the WGC with enough gas to operate normally.

Followup: Yes

Notes: First written report states that emissions were minimized by reducing rates and installing a spare vacuum jet overhead pump. The incident occurred due to the inability to maintain operation of the COker WGC which pulls gases from the Coker and Vacuum Units. While the WGC was down, the Vacuum Jet Receiver was vented to the flare in order to maintain unit operation and avoid a larger flaring event associate with the unit trip. Additionally, the Flare Gas Recovery Unit remained in operation to reduce the amoin of flared gas. The event was secured by completing repairs on the coker and stabilizing the WGC. The following corrective measures were taken to prevent recurrence: 1) Review this incident with affected personnel. 2) Evaluate the piping system for use with temporary jet pumps and redesign as needed to minimize vibration issues. 3) Develop a reliability improvement plan that is based on the findings of the investigation into the jet pump failure. 4) Implement a reliability improvement plan on both in-service and spare coke cutting pumps. 5) Review the WGC operation for continued use at low rates or when the Coker is on circulation. We exceeded the reportable quantity of SO2 as a result of the incident.
440.0 pounds
150290

2013-08-09
6d 14hr 24m
Coker No. 2 Steam Vent
Flares 1,2,3,4&5
Flares 1,2,3,4&5; 30, 1600, & 3700 TOX; FCCU; GDU; Boilers B-401C, B-401D, & 401-E
Flares 1,2,3,4&5; Coker no. 2 Steam Vent
Flares 1,2,3,4&5; Coker No. 2 Steam Vent; Boilers B-401C, B-401D, & 401-E
Flares 1,2,3,4&5; FCCU; GDU; Boiler B-401C, B-401D, & 401-E
Flares 1,2,3,4&5; FCCU; GDU; Boilers B-401C & B-401D
Flares 1,2,4&5; 30, 1600, & 3700 TOX; Coker No. 2 Steam Vent
Flares 1,2,4&5; Coker no. 2 Steam Vent
Cause: On August 9, 2013, at approximately 22:51 hrs, Valero experienced an interruption in power supply caused by a surge arrestor electrical fault. The interruption caused the shutdown of multiple process units and resulted in excess emissions from the boilers, Sulfur Recovery Units (SRUs), Fluid Catalytic Cracking Unit (FCCU), Gasoline Desulfurization Unit (GD), Coker Unit, and refinery flares. During recovery process of the power loss event, shutdowns occurred to both the Hydrocracker unit (HCU) and Ultra-low sulfur diesel unit (ULSD) resulting in flaring. Both unit shutdowns were related to the shutdown of their recycle gas compressors. The HCU's recycle gas compressor malfunctioned due to a low steam pressure which was directed related to the power loss event. The ULSD shutdown due to a malfunction of the recycle gas compressor's primary lube oil pump, and a delayed response for the startup of the secondary lube oil pump. We are unable to determine if the shutdown of the ULSD was directed related to the power loss event. However, the emission contributed to the HCU and ULSD shutdowns are considered as part of the same power loss event and are included herein.

Followup: Yes

Notes: The power loss caused the Crude Unit and Vacuum Unit to shut down immediately, thus preventing the manufacture of intermediates that feed subsequent process units. Downstream units were placed in circulation mode through manually closing valves, lowering reactor temperature and restarting tripped equipment such as compressors and pumps. Steam production was also increased as available to allow units to continue in circulation mode until power was restored. The HCU and ULSD units were re-started to reduce excess emissions. In addition, the flare gas recovery unit remain in operation during the entire incident to reduce the amount of flared gas. To prevent recurrence, the following procedures will be adopted: 1) Perform thermal scans of the surge arrestors in the Prospect and Good Hope Substation yards. 2) Perform routine thermal scans of the surge arrestors in the Prospect and Good Hope Substation yards. 3) Complete the evaluation of all existing Valero owned surge arrestors in the Prospect and Good Hope Substation yards to determine if they are of the same age and model of the T3 arrestors that have shown signs of degradation. To data, the surge arrestors on T4 transformers have been identified as being of the same vintage and design as the failed arrestors and will be the first targeted for replacement as will all arrestors of this design. 4) Evaluate one of the non-failed surge arrestors removed from service to determine if any degradation has started to occur. 5) Develop a plan to routinely replace all surge arrestors in 230KV service at 10 year intervals. 6) Review this incident and emergency procedures with affect personnel. 7) Evaluate raising the autostart pressure setting on the auxiliary lube oil pump. 8) Evaluate increasing the trip time delay on the low-low lube oil shutdown. 9) Consider installing a valve on the make-up hydrogen at the ULSD unit battery limits to prevent fresh hydrogen from being introduced to the unit during a period of malfunction. 10) Add to existing Emergency Operation Procedure to account for Diamond Green Diesel, which is connected to the ULSD. 11) Contact corporate hydrocracking specialists to determine if the logic should be modified to initiate high rate depressurization upon loss of recycle gas compressor. Reportable quantities were exceeded for H2S, SO2, NOx, and VOCs.
3,764.0 pounds
149758

2013-07-17
Flare 1,2
Cause: Valero experienced intermittent flaring from Flares 1 and 2 when the slop oil degassing drum exceeded the capacity of our flare gas recovery system. On July 17, 2013 intermittent flaring from flares #1 and #2 started. The source was initially unknown and being investigated. The flaring was discovered to be associated with the startup of the hydrocracker unit, which began on July 12, 2013. Per startup procedure, off-spec product (naptha)was rerouted to the rerun tank, which allows the recovery and reprocessing of this material. On the way to the rerun tank, the naptha was degassed to the flare header so that the light hydrocarbons are kept out of the tank. Normally, these light hydrocarbons are then collected by flare gas recovery and returned to our fuel gas system. However, after about four days after the startup procedure was initiated, these vapors exceeded the capacity of the flare gas recovery system, causing intermittent flaring from flares #1 and #2. The flaring ceased when the off-spec product was routed to the gasoline blending tanks instead of the rerun tank.

Followup: Yes

Notes: Emissions were minimized by localizing and redirecting the source of the flare gas to another unit. In addition, the flare gas recovery unit remained in operation to reduce the amount of flared gas. The following corrective actions have been identified to prevent recurrence: 1) Review this incident with affected personnel and attach a sign-off sheet. 2) Revise the startup procedures to address this situation.
286.0 pounds
148110

2013-04-14
Flares 1, 2, and 4
Cause: On April 14, 2013, at approximately 07:Sl, the Coker WGC malfunctioned, resulting in a unit shutdown and a release to the flare of approximately 47,S36 pounds of sulfur dioxide and 144 pounds of hydrogen sulfide. The WGC tripped offline and could not be restarted due to a malfunction of the compression thrust bearing. Monitoring of the compression thrust data did not indicate prior degradation of the bearing. The bearing is believed to have failed from steam condensation due to a boiler malfunction approximately 2S minutes before the WGC tripped. The boiler malfunction caused the steam temperature to drop to the saturation point. Additionally, there was missing and damaged insulation found along the steam header upstream of the WGC. The missing insulation along with the heavy rain that was in the area during the time of the incident could have contributed to the drop in steam temperature to the saturation point. Emissions were minimized by reducing the crude rate by approximately SO percent and by shutting down the delayed coker unit.

Followup: Yes

Notes: Emissions were minimized by reducing the crude rate by approximately 50% and by shutting down the delayed coker unit. Follow up report details procedures or measures which have or will be adopted to prevent recurrence: 1. Communicate this incident to all affected personnel 2. Replace missing or damaged insulation on the steam header 3. Evaluate Mud Legs for performance and adequacy 4. Evaluate the need for an inline separator on the 650-lb steam to the WGC 5. Perform an infrared (IR) camera scan of the 650-lb steam header
27.0 pounds
146729

2013-02-19
Flares 1, 2, 3, and 4
Cause: On February 19, 2013, at approximately 04:10, the Diesel Hydrotreating (DHT) Recycle Gas Compressor (K-15-53) malfunctioned resulting in a unit shutdown and a release to the flare of 828 pounds of sulfur dioxide. The GE Multilin relay indicated a short due to apparent moisture intrusion that caused arcing which damaged the insulators and cables. Heavy rain was in the area at the time of the incident.

Followup: Yes

Notes: Safely shutdown the DHT. No pollutants were recouped. Emissions were minimized by restarting the recycle gas compressor. The cables were repaired and the insulators were replaced. A cover for the capacitor cabinet was fabricated to cover the holes due to rust which allowed water inside to prevent any further damage from inclement weather. To prevent recurrence, the following procedures have or will be adopted: 1) Communicate this incident to all affected personnel. 2) Replace the existing cabinet on the next turn-around. 3) Modify the existing roof/cover to provide better protection from inclement weather. (A temporary repair was already completed.) 4) Survey similar cabinets for damage and make required repairs and/or replacements. 5) Establish preventative maintenance program for similar cabinets plant-wide. 6) Determine the necessity of the capacitors for K-15-53 and either replace or remove them. 7) Improve effectiveness of and/or training on the maintenance work process to ensure that repair findings/discovery scope during the course of work that is not addressed at the time is captured in a work order. 8) Draft an emergency operating procedure to address the loss of the recycle compressor. SO2 reportable quantities were exceeded. A report was issued on 4/19/2013 stating that Valero was "unable to complete the investigation within 60-days of the above referenced incident".
548.9 pounds
146196

2013-01-21
Flare 1 and 2
Cause: The wet gas compressor in the delayed coking unit had malfunctioned. The Wet Gas Compressor (WGC) malfunction resulted from a malfunctioning lube oil turbine. The nigh prior to the incident, the lube oil turbine tripped. The backup electric pump started in "auto" to control the lube oil pressure. We restarted the lube oil turbine but were unable to shutdown the backup electric pump with the switch in 'auto'. We verified that the lube oil pressure was stable and then shutdown the electric pump. The lube oil turbine then tripped on overspeed and when we switched the backup electric pump from 'off' to 'auto' it did not restart causing the WGC compressor to trip from low lube oil pressure. We determined that the electric pump did not restart because it received a single pulse start signal that was sent before the pump was put in 'auto' causing it not to register. Additionally, the original overspeed trip was due to scoring on the Fischer actuator due to its tendency to side load. The scored piston caused the actuator to stick resulting in a lack of speed control.

Followup: Yes

Notes: The maximum hourly permitted emissions for hydrogen sulfide and sulfur dioxide at flares 1 and 2 were exceeded. The reportable quantity for sulfur dioxide was also exceeded. Emissions were minimized by restarting the wet gas compressor. Gas from the coker was combusted in Flare 1 and Flare 2, and the resulting combustion byproducts rapidly dispersed.
1.6 pounds
159934

2014-11-09
Hydrocracker-Hydrotreater
Cause: On 11/9/14 at approximately 21:30 hours, the Hydrotreater-Hydrocracker (HTHC) Recycle Compressor malfunctioned, which initiated a shutdown of HTHC and led to a reportable quantity of sulfur dioxide. The cause of the malfunction is under investigation.

Followup: No

Notes: Emissions were minimized by shutting down and then restarting the HTHC unit. Air monitoring was conducted in the downstream wind direction within and around the refinery. The incident is still under investigation to determine preventative measures.
17.9 pounds
157325

2014-07-09
EQT 0360 Flare No. 4
Cause: The Hydrotreater/Hydrocracker (HTHC) recycle compressor malfunctioned, which initiated a shutdown of the HTHC and led to a reportable quantity of sulfur dioxide. The cause of the malfunction is under investigation while the unit is being repaired. Permitted emissions for H2S, VOC and SO2 was exceeded for 1 hour. The unit depressured in approximately 15 minutes, however, due to the excess production of hydrogen following the HTHC shutdown, Valero continued to flare hydrogen. Valero submitted a Notification of Case by Case insignificant activity on July 11, 2014 to cover emissions from Hydrogen flaring; therefore, hydrogen flaring was not considered within the duration of this event. Valero exceeded hourly permitted emissions for hydrogen sulfide, volatile organic compounds and sulfur dioxide at Flare 4 for one hour.

Followup: Yes

Notes: Shutdown of HTHC unit. Air monitoring was conducted downwind of the refinery. No procedures or preventive measures given at the time of the report. Follow up report lists the following measures identified to prevent recurrence: 1) Review this incident with affected personnel and attach sign off sheet 2) Investigate installing knock out put upstream on dry gas seal (DGS) panel inlet filters with continuous blowdown 3) Investigate the need for level indication and drains on the make-up gas (MUG) discharge pulsation dampers 4) Use recycle gas to supply panel when sufficient differential pressure is available and modify procedures accordingly 5) Evaluate the functionality of the TriLogger system and determine if upgrades are needed 6) Review the lubrication program for HTHC compressors 7) Run drain lines from the dry gas seal panel filters to a safe location for liquid removal
17.9 pounds
157159

2014-07-01
3700 Sulfur Recover Unit
Cause: The 3700 Sulfur Recover Unit (SRU) furnace main air safety shutdown valve closed unexpectedly, which initiated a 3700 SRU trip and led to excess emissions of sulfur dioxide. While troubleshooting the malfunction, operators shifted the amine acid gas feed (AAG) from 3700 SRU to two remaining units (1600 and 30 SRU). The move caused excess emissions from the 30 SRU while stabilization was in process. About 30 minutes later, the malfunctioning valve reopened, reintroducing AAG into SRU 3700 and causing a RQ emission for sulfur dioxide. Later in the same day, at approximately 20:45 the 3700 SRU reaction furnace main air safety shutdown valve closed again. After the second malfunction, Valero purposely shut down the 3700 SRU in order to further troubleshoot the issue, and then implemented sulfur shedding in order to reduce sulfur loading to the SRUs. Sulfur shedding included: decreasing throughput of the Hydro-Treater, Hydro-Cracker (HTHC) unit to minimum rates, reducing overall refinery crude throughput, shifting amine acid gas feed to the two remaining operating SRUs (1600 and 30 SRUs), and shutting down sour water acid gas feed (SWAG) to the remaining two SRUs. The quick shift in AAG feed to the remaining two SRUs resulted in excess emissions from the 30 and 1600 SRUs for approximately 1 hour while making the necessary adjustments for the increased AAG loading to the units. The additional loading at the 30 SRU caused the 30 Thermal Oxidizer (TOX) to trip offline at 21:52 hrs due to low oxygen for combustion. It was brought back online at approximately 23:32. However, during the outage Valero experienced elevated hydrogen sulfide emissions from the 30 TOX. When the 30 TOX tripped, they had trouble restarting it due to wires that were found to be corroded and detached from the terminated position. The wire was tied to a system that was needed to complete the logic to start the TOX. The corroded wires were repaired, the termination box was properly sealed and the TOX was restarted. An investigation into the SRU 3700 reaction furnace main air safety shutdown valve malfunction revealed a loose wire as the cause. Valero repaired it, restarted the 3700 SRU, and resumed normal operation.

Followup: Yes

Notes: Emissions were minimized by shutting down the 3700 and reducing the feed to upstream operating units. Subsequently, repairing and restarting the 3700 SRU reduced sulfur loading on the 30 and 1600 SRU, which allowed those units to resume normal operation. Air monitoring was conducted in the downstream wind direction within and around the refinery, and no detectable SO2 or H2S was found using portable air monitoring equipment. The following corrective actions were identified: 1) Review the incident with all affected personnel 2) Review the requirement to evaluate the condition of the sealing system of any instrument enclosure that is opened while performing any maintenance task associated with routine or preventative maintenance 3) Remove the logic for the 30 SRU atomizing stream valve from the purge permissive and pilot permissive.
33.2 pounds
155645

2014-04-30
Flare 1
Flares 1, 2, 3
Cause: The fluid cat cracking unit (FCCU) wet gas compressor shut down due to a loss of power that resulted from a transformer short circuit and a circuit breaker malfunction. As a result, flaring occurred from permitted flares 1, 2 and 3. Workers reduced total feed and reactor temperature in the FCCU to minimize flaring until compressors could be restarted. Transformer failed in the EP-03A substation. A relay setting associated with this system was not set properly and allowed the fault current to reach the Good Hope Substation. The fault was cleared by the breaker at the Good Hope Substation. As a result, several other transformers also tripped and upset the FCCU. This accident exceeded maximum hourly permitted emissions for sulfur dioxide, hydrogen sulfide, hexane, and Volatile Organic Compounds at Flare 1 for one hour. Maximum hourly permitted emissions were also exceeded for NOx and carbon monoxide at Flare 2 for one hour. Maximum hourly permitted emissions for sulfur dioxide and Volatile Organic Compounds at Flare 2 for 5 hours. Reportable quantities for sulfur dioxide and propylene were exceeded.

Followup: Yes

Notes: At the time of the accident, emissions were minimized by reducing the overall rate to the unit and reactor temperature. Operators responded by adjusting the power distribution system in order to reestablish the poewr source and restart the compressors. Throughout the event, the Flare Gas Recovery Unit remained in operation to reduce the amount of flared gas. Process changes have been implemented as corrective actions. These include: - updated relay settings - refinery arch flash study and relay setting review - even distribution of four P82-808 pumps across the electrical feed buses - modify MOC checklist to include relay settings and coordination curves - modify PSSR checklist to include relay settings and coordination curves - require all new or changed relay setting requested through CSE with relay setting/coordination curve request form - communicate incident to affected personnel - communicate incident and path forward to CSE electrical engineers, MP electrical engineers and maintenance electrical supervision
1,229.9 pounds
155480

2014-04-23
Flare 1, Flare 2, and Flare 3
Cause: Valero experienced flaring from Flares No. 1, 3, and 4 when Coker Wet Gas Compressor (WGC) malfunctioned during a planned shut down. During the shut down the flow to the WGC increased when the sponge oil absorber was emptied. The emptied oil absorber increased the load to the 1st stage suction of the compressor, which caused the turbine speed to increase to compensate for the additional load. Later that evening, an operator heard gas going through LV-53-505 on the Sponge Oil Absorber and requested console operator to close the valve in order to decrease compressor loading. However, the valve was closed too quickly, which caused the WGC to trip offline and gases to be routed to the flare system. Report states that flares are "permitted for planned startup/shutdown operations in addition to flare operating limits". Those increased permit limits for each flare are included in the report. This accident resulted in the exceedance of the maximum hourly permitted emissions for hydrogen sulfide and sulfur dioxide, the 3-hour rolling average for hydrogen sulfide in the West Plant and CCR Fuel Gas and the reportable quantity for sulfur dioxide.

Followup: Yes

Notes: Emissions were minimized by completing the shut down of the Coker Unit. Additionally the flare gas recovery unit collected and rerouted some of the gases back to refinery fuel gas. The following corrective actions have ben identified to prevent recurrence: Communicate incident to affect personal (Estimation completion date 7/31/140 Edit the Coker shutdown SOP to include a warning about high suction pressure/ high RPM scenario (Est. Completion date 7/31/14) Modify the distributed control system to display a warning when the compressor is approach a high suction pressure/high RM state (Est. Completion date 7/31/14) In addition to communicating the incident to all Coker personal, review the specifics with shift supervisors, console operators, and set up operators. Focus this communication on recognizing that gas flow through a liquid valve is unusual and may require cautious, measured moves to correct (Est. Completion date 7/31/14) Guardian OST. (Est. Completion date 6/20/14) Develop a WGC training overview for operators and supervisors (Est. Completion date 8/31/14) Review alarm points (Est. Completion date 7/31/14) Start monthly "what if" drills on the compressor operation (Est. Completion date 7/31/14) There is no record that any of these corrective actions have be mandated or not and the plan of action did not take into consideration of notifying the nearby communities.
134.9
153607

2014-01-29
Flares 1 and 2
Cause: On January 29, 2014, the Valero St. Charles Refinery (Valero) experienced flaring when the pressure on the Naphtha Surge Drum and the Wet Gas Compressor (WGC) Interstage Drum increased. The pressure controller on the Naphtha Surge Drum malfunctioned due to cold temperatures, which caused the level to rise in the drum. As a result, the level in the Compressor Interstage Drum, which is downstream of the Naphtha Surge Drum, increased and caused the WGC to trip. The pressure controller on the Naphtha Surge Drum was bypassed to the flare header in order to control high levels on additional upstream and downstream vessels with the unit. Flaring stopped after the level in the Compressor Interstage Drum was decreased and the WGC was restarted. Temperatures were below 30degF on the morning of the incident. It was found that the steam tracing on the pressure controller on the naphtha surge drum was not in contact with the valve and insulation blankets were not in place. The lack of steam tracing and insulation exposed the valve to cold temperatures, which caused it to malfunction.

Followup: Yes

Notes: The event was secured by reducing the level in the compressor interstage drum and restarting the WGC. Additionally, the Flare Gas Recovery Unit remained in operation to reduce the amount of flared gas. The following corrective measures have been identified to prevent recurrence: 1. Review this incident with affected personnel. 2. Review and revise as need the freeze protection guidelines. 3-7. Create a pre-winter checklist to identify and correct tracing and insulation issues for Complexes I-V. 8. Repair the steam tracing and insulation for PCV-53-471, LV-53-472, LV-53-020, and LV-53-038. The Reportable Quantity for SO2 was exceeded.
328.0 pounds