Home Search Emissions Pollutants About the Database

Valero (26003), Norco

Releases in 2013

LDEQ Accident Number
Accident Date
Point Source/Release CauseNotes

Point Source(s):
Flare 1

NOx - 113 pounds
Carbon Monoxide - 617 pounds
Particulate Matter - 4 pounds
Sulfur Dioxide - 2,232 pounds
Hydrogen Sulfide - 12 pounds
Volatile Organic Compounds (VOCs) - 440 pounds
Cause of Problem: Maintenance/Procedures

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.
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.

Point Source(s):
1600 Sulfur Recovery Unit

Sulfur Dioxide - 49 pounds
Hydrogen Sulfide - 0 pounds
Cause of Problem: Equipment Failure

On Monday October 14, 2013, at approximately 14:15 hrs, we made notification that we potentially exceeded a reportable quantity for sulfur dioxide due to a malfunction of the 1600 sulfur recovery unit (SRU). After further investigation, we have determined that no reportable quantity has been exceed resulting from this incident.
Air monitoring conducted with the refinery and along the fence line of the refinery downwind of the prevailing wind direction revealed no appreciable SO2 concentrations (0 ppmv SO2). Report states that excess emissions will be captured in a future Title V report.
No LDEQ Number Available

Point Source(s):
None Reported
Cause of Problem: Maintenance/Procedures

On Friday September 13, at approximately )5:32 hrs, a courtesy call was made to the State Policy and St. Charles DEP, stating that a flash fire occurred in T-04-32, which was out of service and being cleaned.
There were no injuries from the incident. The ERT was mobilized as a precautionary measure.
No LDEQ Number Available

Point Source(s):
transfer line at Dock 5

Slurry Oil - 25 gallons
Cause of Problem: Corrosion

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.
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.

Point Source(s):
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

Nitrogen Dioxide - 8,065 pounds
Carbon Monoxide - 18,171 pounds
Particulate Matter - 336 pounds
Sulfur Dioxide - 71,472 pounds
Hydrogen Sulfide - 652 pounds
Volatile Organic Compounds (VOCs) - 3,764 pounds
1,3-Butadiene - 12 pounds
Benzene - 26 pounds
Ethylbenzene - 0 pounds
Formaldehyde - 1 pounds
Naphthalene - 2 pounds
Hexane - 263 pounds
Cresol - BRQ
Polycyclic Aromatic Hydrocarbons - 1 pounds
Toluene - 15 pounds
Xylene - 9 pounds
Phenol - 0 pounds
Phenylamine - 0 pounds
Cause of Problem: Power Failure

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.
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.

Point Source(s):
Pressure line to T-50-3

Sulfuric Acid - 200 gallons
Cause of Problem: Seal or Gasket

After an investigation, it was determined that the spill on line T-50-3 was due to a gasket failure that resulted from thermal expansion of a liquid in a fixed length section of pipe. The incident occurred during a regulatory pressure test, where an area of pipe containing spent sulfuric acid was blocked between two closed valves. The ambient temperature was above 90 degrees F, and heat from the sun caused the material in the pipe to increase pressure. The abnormally high pressure from thermal expansion pushed the gasket and, in the absence of a thermal relief valve, caused the gasket to malfunction.
As a precaution, hand held air monitoring devices were used within the refinery (with respect to wind direction), along River Road and Prospect Ave. See note. Most of the acid that was spilled into the containment was removed using a vacuum truck. Soda ash was used to neutralize any residual acid in the area. The contaminated soil was excavated and stored in rollout boxes and properly disposed. We will implement the following corrective actions a result of incident investigation: 1) Modify the piping system at the tank to include a thermal relief system. 2) Modify guidelines to reflect thermal expansion as an issue during this test. 3) Review the incident with affected personnel, and train them on the hazards associated with thermal expansion. 4) Ensure piping of new tank in similar service has proper relief. Note: Readings for CO, H2S, VOC, and SO2 read 0 ppm at multiple sites downwind (north/northwest of the incident). Nuisance odor was present near the FCCU. The onsite air monitoring station was continuously taking SO2 readings, although this is located in the southeast of the area, which is the opposite of the wind direction during the event. The readings for this area were on average 2.1 ppb at the time of the incident and throughout the cleanup process.

Point Source(s):
Flare 1,2

NOx - 139 pounds
Carbon Monoxide - 756 pounds
Sulfur Dioxide - 3,769 pounds
Hydrogen Sulfide - 20 pounds
Volatile Organic Compounds (VOCs) - 286 pounds
Particulate Matter - 5 pounds
Cause of Problem: Process Upset

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.
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.

Point Source(s):
Dock 2

Heavy Premium Coker Gas Oil - 30 gallons
Cause of Problem: Equipment Failure

On June 21 at approximately 17:30 while loading to a barge at dock 2, approximately 30 gallons of Heavy Coker Gas Oil was spilled to the Mississippi river due to a malfunction of the loading arm. The failure occurred because the locking pin on the loading arm was engaged while transferring product to the vessel. The loading arm and counterweight could not move freely with the vessel. The locking pin is spring loaded and held out of the path of the counterweight with a small diameter wire. The wire failed and allowed the locking pin to become engaged. As the vessel was filled, the weight of the oil caused it to sit lower in the river and caused the loading arm to separate from the connection to the vessel. A weld failed on a 12" pipe located at the base of the loading arm which caused a 1/5" wide by 5" long hole in the pipe. Coker gas oil sprayed 10 feet from the facility and onto the barge.
All valves were isolated and the transfer was shutdown to prevent additional leakage. Absorbent pads and boom were used to capture any remaining oil. The contracted emergency response vendor was mobilized to assist with the cleanup. The following corrective measures have been or will be implemented to prevent this recurrence: 1) Modify locking pin mechanism so that it is not spring loaded with an engineered connection threaded rod device, 2) Review incident with all Complex 1/SGS (dock operators) personnel for improved hazard recognition, 3) Review inspection procedures with dock personnel including frequency and documentation, 4) Develop a way for SGS operators to have access to input work notifications in SAP, 5) Have a meeting with the North Wind Fab Inc. to incorporate loading arms into the inspection system and ensure all locking pin mechanisms are included in the inspection report.

Point Source(s):
block valve

Propylene oxide - 1,309 pounds
Cause of Problem: Piping or Tubing

On June 13th, 2013 at approximately 12:20 pm, the reserve plant control systems alerted the control systems operator of a high scrubber temperature condition. The board operator followed procedure by monitoring the scrubber for increasing temperatures. At approximately 12:35 pm, the reserve plan control system alerted the control board operator of high-high temperature condition for the scrubber system. The board operator responded by shutting down operations in a controlled manner, after which he began field inspections of the scrubber systems and oxide systems. Upon further investigation the operator identified a block valve for the propylene oxide unloading system not fully closed, allowing propylene oxide to backflow through the low pressure vent line to the scrubber.The block valve was manually closed and propylene oxide flow to the scrubber was stopped. Initial evaluation determined that a block valve pneumatic actuator malfuntioned allowing propylene oxide to flow through the low pressure vent to the scrubber.
Immediate Corrective Actions: Activation of plant EOC and shutdown of oxide movement valve closure to the propylene oxide unloading block valve N2 blowback of lines to propylene oxide storage tank Maintenance request submitted for actuator and valve replacement Long Term Corrective Actions: Schedule a root cause analysis of incident to identify long term corrective actions intended to prevent re-occurrence Ensure Maintenance replaces block valve actuator Follow up with maintenance to ensure preventative maintenance is preformed on block valve Review other valves and actuators in oxide service for same issue

Point Source(s):
debutanizer column vent

Sulfur Dioxide - 290 pounds
Propylene - 83 pounds
Cause of Problem: Process Upset

On June 4, 2013 at approximately 0930 hrs, the loss of heat medium in the debutanizer column caused controlled venting of sulfur dioxide and propylene.
A notification was made that a reportable quantity for sulfur dioxide and propylene was exceeded. After further review, it was determined that no reportable quantity has been exceeded resulting from this incident. Emissions associated with this malfunction will be captured in the Title V semiannual deviation report.

Point Source(s):
storm water sump pump

Crude Oil - 50 gallons
Cause of Problem: No Information Given

On May 13, 2013 at approximately 1030 hrs, 1 barrel of crude oil was discovered. After further investigation, it was discovered that within our dike area of our storm water sump pump, a total of 50 gallons was spilled over a 48 hour period.
Oil was recovered from earthen sump using absorbent materials and a vacuum truck. Impacted soil excavated from impacted area for disposal. Some reports state 1 barrel, or 42 gallons, spilled and others state 50 gallons have been released. Notification considered a courtesy, although the RQ for crude oil is 1 barrel.

Point Source(s):
Flares 1, 2, and 4

Sulfur Dioxide - 47,536 pounds
Hydrogen Sulfide - 144 pounds
NOx - 662 pounds
Volatile Organic Compounds (VOCs) - 27 pounds
Carbon Monoxide - 3 pounds
Particulate Matter 10 - 22 pounds
Cause of Problem: Under Investigation

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.
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

Point Source(s):
30 TOX stack

Sulfur Dioxide - 670 pounds
Cause of Problem: Under Investigation

The 30 SRU malfunctioned resulting in excess sulfur dioxide emissions to the atmosphere. Excess emissions were emitted from the 30 TOX stack to the environment and rapidly dispersed.
The permitted SO2 rate was exceeded and reportable quantity were exceeded for the reporting hour of 11:00. Total SO2 emissions for the reporting hour of 11:00 were approximately 666 lbs., and total SO2 emissions in excess of the permitted limit were 551 lbs.

Point Source(s):
Flares 1, 2, 3, and 4

Sulfur Dioxide - 828 pounds
Carbon Monoxide - 1,451 pounds
NOx - 267 pounds
Particulate Matter - 11 pounds
Volatile Organic Compounds (VOCs) - 549 pounds
Hydrogen Sulfide - 4 pounds
Cause of Problem: Power Failure

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.
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".
No LDEQ Number Available

Point Source(s):
Loading Arm No. 3

Light Cycle Oil - 2 gallons
Cause of Problem: No Information Given

On Febraury 6, 2013 at approximately 20:25 while the dock operations contractor connected Loading Arm No. 3 to the EMS-321 barge on Dock 3, less than two gallons of Light Cycle Oil (LCO) spilled into the river. The remaining material was contained in a drip pan on the barge. Prior to initiating the connection, the loading arm had been cleared using pressurized air to another barge. However, a pocket of LCO remained in the arm and discharged while making the connection. The oil spilled to the river and dissipated. The remaining oil on the barge structure was cleaned. Waste from the clean-up will be shipped offsite to a non hazardous waste landfill.
While attaching the loading arm, a drip pan was used to contain any free oil, and we verified that all transfer lines were isolated. Absorbent pads and boom were used to capture any remaining oil. The barge company provided personnel to clean the residual oil on their deck and associated piping. No usable material was recovered. The recovered waste was disposed of properly. The following corrective measures will be implemented to prevent this recurrence: 1. Modify procedures to use alternate systems to strip the loading arms using pumps instead of pressurized air. 2. Develop a scope and cost to investigate a permanent system to strip the loading arm to the LCO transfer line. 3. Modify dock log to note loading arm stripping activities and time of activity. *The attached PDF defines itself as a 60 day written follow-up report. No LDEQ number is listed on the document. LABB could not locate the original 7-day refinery letter. The report lists LA Police incident 13-00567, NRC 1037776, but no LDEQ incident number. 4. Communicate the incident to all dock personnel.
No LDEQ Number Available

Point Source(s):
EMS-321 barge

Light Cycle Oil - 2 gallons
Cause of Problem: Under Investigation

While connecting Loading Arm #3 to the EMS-321 barge on Dock 3, less than two gallons of Light Cycle Oil (LCO) spilled into the river and dissipated.
The remaining material was contained in a drip pan on the barge, approximately one gallon. Absorbent pads and booms were used to capture any remaining oil. No usable material was recovered; recovered wasted will be characterized and disposed of properly.

Point Source(s):
Flare 1 and 2

Carbon Monoxide - 217 pounds
NOx - 40 pounds
Particulate Matter - 1 pounds
Volatile Organic Compounds (VOCs) - 2 pounds
Sulfur Dioxide - 5,559 pounds
Hydrogen Sulfide - 15 pounds
Cause of Problem: Equipment Failure

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.
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.