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Valero (26003), Norco

Causal Factor: Corrosion

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

Tank - T-130-9
Cause: tank leaking VGO through floor

Followup: No

Notes: Emergency team mobilized to pump VGO to another tank. Emergency respose company contracted to recover non-pumpable VGO and perform soil remediation. Valero will begin to use acoustical testing on all of its tanks.
Vacuum Gas Oil: 2,100,000.0 gallons

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.
Carbon Monoxide: 1,290.0 pounds
Nitrogen Dioxide: 1,419.0 pounds
Total Organic Carbon: 1,084.0 pounds
Sulfur Dioxide: 13,095.0 pounds
Hydrogen Sulfide: 91.0 pounds
Particulate Matter: 258.0 pounds
Carbon Monoxide: 128.0 pounds
Nitrogen Dioxide: 24.0 pounds
Particulate Matter: 1.0 pounds
Volatile Organic Compounds: 48.0 pounds
Sulfur Dioxide: 4,839.0 pounds
Hydrogen Sulfide: 13.0 pounds

tank t-130-6
Cause: Crude oil was leaking from tank T-130-6. Operator noticed leak after filling the tank with oil. There were holes in the tank caused by both internal and external corrosion.

Followup: Yes

Notes: Tank was filled with water to lift oil away from the leak. Tank was emptied, degassed to a control device, cleaned, and taken out of service for repair. Oil was recovered, and soil was sent off-site for hazardous waste disposal.
Sour Crude: 4,200.0 gallons

Tank 50-1: Sulfuric Acid Pipeline
Cause: Refinery letter states that a leak occurred in a sulfuric acid pipeline due to interior corrosion of the pipeline. Section 3 of tank area, near Tank 50-1.

Followup: Yes

Notes: RQ. Reportable quantity for sulfuric acid was exceeded. After donning protective gear, the tank farm operator immediately closed the valve to prevent any additional discharge. Personnel was mobilized to begin the remediation process. Some acid was recovered, using a stainless steel vacuum truck. The pressure indicator was removed from the fresh acid line and replaced with a blind flange. Operations will utilize the PI located on the pump discharge line for future readings. A routine visual inspection of all vents, bleeders, flanged connections, and PI's on the fresh acid system will be implemented.
Sulfuric Acid: 1,540.0 pounds

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.
Benzene: 1,027.0 pounds
Volatile Organic Compounds (VOCs): 37,495.0 pounds
No LDEQ Reported

transfer line at Dock 5
Cause: On September 12, we discovered at approximately 05:30 that a leak had developed on a 16" line while in use to transfer slurry oil to a vessel at our Dock 5. This resulted in a 15 gallon slurry oil spill to the batture [i.e. land]. The volume of oil that entered the river cannot be confirmed, but is estimated on the order of 10 gallons. The density of the oil caused it to sink to the bottom, which does not allow for accurate quantification of the total volume that entered the river. This failure is attributed to corrosion under the insulation of this transfer line. A repair plan for the corrosion was being executed as a result of the 2012 inspection, but a small, intermittent leak on an adjacent water line caused the corrosion at this point to be accelerated. The water leak was discovered as a result of this incident investigation. The known damage of the insulation on certain locations of the transfer line also contributed to this moisture driven corrosion.

Followup: Yes

Notes: Once the leak was identified, the line was isolated and boom was deployed into the river. Containment and absorbent pads were placed under the leak site to capture any residual oil and a vacuum track was deployed to remove the remaining contents of the line. Absorbent boom was placed on the shore to prevent additional oil from going to the river and to capture oil possibly in the water already. Our contracted oil spill response organization was mobilized to assist with the cleanup. The oil that spilled to the dirt was removed with a vacuum truck. The in the area was excavated and placed into roll out boxes for disposal. The oil spilled to the river sank to the sediment. Some oil was captured using absorbent boom or was found on the side of the docked barges. This oil was removed and disposed as non-hazardous waste. The following corrective measure have or will be implemented to prevent this recurrence: 1) Repair the line by replacing sections of old pipe. 2) Take the Reduced Crude Line out of service, inspect and repair if necessary before putting back into service. 3) Review incident with all Complex I/SGS (dock operators) personnel for improved hazard recognition. 4) Develop an overall inspection plan on the remaining, insulated batture piping. 5) Confirm that all batture piping from Dock 4 to Dock 5 is inspected.
Slurry Oil: 25.0 gallons