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Valero (26003), Norco
Releases of Benzene
| LDEQ Accident Number Accident Date |
Point Source(s) | Notes | Amount of Release |
| 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. | 59.0 pounds |
| 117821 2009-09-09 | No information given. | Cause: Leak in the piping on the outlet of waste water Tank 325-1. Followup: No Notes: No information given. | 1.0 pounds |
| 122782 2010-04-14 | Oily Wastewater Sewer Line | Cause: Refinery letter states a leak occurred in the underground oily wastewater sewer line in the crude unit. Followup: No Notes: Further remedial action was conducted in the area to properly dispose of all contaminated soil and fill material. Samples will be taken to ensure a proper clean-up. Less than .0001 lbs of CYANIDE were also released. | 0.0 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. | 0.0 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. | 1,027.0 pounds |
| 131415 2011-05-20 | 30, 3700, and1600 Unit Thermal Oxiders, Flares 1 and 2 1600 TOX and 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. | 72.9 pounds |
| 150290 2013-08-09 | 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 1,2,3,4&5; 30, 1600, & 3700 TOX; FCCU; GDU; Boilers B-401C, B-401D, & 401-E Flares 1,2,4&5; 30, 1600, & 3700 TOX; 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 Flares 1,2,3,4&5; Coker no. 2 Steam Vent Flares 1,2,4&5; Coker no. 2 Steam Vent Coker No. 2 Steam Vent 6d 14hr 24m | 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. | 26.0 pounds |
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