|Home||Search||Emissions||Pollutants||About the Database|
|LDEQ Accident Number
|Point Source(s)||Notes||Amount of Release|
|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.|
Notes: ERT extinguished fire in 20 mins.
|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.|
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.
|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.|
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