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Valero (26003), Norco

Causal Factor: Process Upset

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

Flare 1 EIQ 15-77; Flare 2 EIQ 12-81
Cause: The wet gas compressor tripped due to a high level in the suction drum.

Followup: Yes

Notes: Emissions were minimized by cutting crude rats and restarting the coker WGC.
Sulfur Dioxide: 8,000.0 pounds

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.
Sulfur Dioxide: 3,008.0 pounds
Particulate Matter: 1.0 pounds
Hydrogen Sulfide: 8.0 pounds
Volatile Organic Compounds: 37.0 pounds
Carbon Monoxide: 98.0 pounds
Nitrogen Oxide: 18.0 pounds

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


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.
Sulfur Dioxide: 11,033.0 pounds
Carbon Monoxide: 1,378.8 pounds
Nitrous Oxide: 253.4 pounds
Particulate Matter: 8.1 pounds
Volatile Organic Compounds (VOCs): 521.6 pounds

Coker Amine Unit
Cause: High Hydrogen Sulfide in refinery fuel due to a coker amine contactor upset

Followup: No

Notes: The upset was successfully corrected in a controlled manner


Coker wet gas compressor trip from high level in the interstage drum
Cause: Wet gas compressor tripped due to a high level in the suction drum Gas processed by the compressor was directed to the refinery flare system

Followup: Yes

Notes: SO2 released from flares and dispersed. Emissions were minimized by cutting coker charge rates, emptying the liquid level to the interstage drum, and restarting the coker WGC. Flaring of gases stopped upon startup of the coker WGC.
Sulfur Dioxide: 5,600.0 pounds
No LDEQ Reported

FLARE - Flares #1 and #2
Cause: Due to a malfunction governor on the turbine and a malfunction pilot valve, the Coker Wet Gas Compressor tripped, resulting in the overhead receiver relieving to the flare. The vendor was contacted for assistance and it was discovered that there was a malfunction of the lube oil system regulator. No documentation on the proper operation of the lube oil regulator system could be found.

Followup: No

Notes: 1) Replace pilot valve. 2) Contact vendors to establish the correct settings, procedures and proper labeling for the operation fo the lube oil pressure regulating system. 3) Add a three second delay time on the low lube oil pressure shut down. 4) Audit refinery for similar mechanical systems. 5) Train instrumentation group on the operation and maintenance of regulator systems.
Hydrocarbon: 4,560.0 pounds

Thermal Oxidizer #1
Cause: On September 12, 2007, Valero had excessive Sulfur Dioxide emissions due ot a process upset in its SRU 3700 unit. Feed to the unit contained a level of hydroCarbon that resulted in a shut down of the Thermal Oxidizer. This oxidizer (3700 TOX) shut down at 20:05 and 20:16 hrs the same day for the same reason.

Followup: Yes

Notes: Oxygen going to the SRU 3700 was increased in order to stabilize the unit.


Thermal Oxidizer #2
Cause: In Valero's SRU 30 unit, one of the feeds to the unit contained hydroCarbon, which upset the normal operating parameters in the unit. Consequently, it caused excess Sulfur Dioxide emissions.

Followup: Yes

Notes: They tried to remove the hydroCarbon in the feed and stabilized the process unit.


Thermal Oxidizer #2
Cause: On September 3, 2007, Valero encountered process problem in its SRU unit. One of the sulfur traps malfunctioned. Consequently, it caused excess Sulfur Dioxide emissions from the Thermal Oxidizer that were dispersed.

Followup: Yes

Notes: They cleaned the trap, reseated the ball, and put the sulfur trap back in service.


Thermal Oxidizer #2 (EQT 196 (99-4))
Cause: In Valero's SRU 30 unit, one of the feeds to the unit contained hydroCarbon, which upset the normal operating parameters in the unit. Consequently, it caused excess Sulfur Dioxide emissions.

Followup: Yes

Notes: Reduced the feed containing hydroCarbon to the unit and minimized the hydroCarbon in the feed.


Wastewater Treatment Unit
Cause: WWTU experienced an upset and oil was carried through the unit into the treatment pond system

Followup: No

Notes: Absorbent boom used to contain oil.
Crude Oil: 420.0 gallons

Thermal Oxidizer #1 (EQT 195 (99-3))
Cause: an obstruction blocked the #4 run down sulfur trap from closing, allowing vapors to back flow through TOX

Followup: No

Notes: Letter states that emission were BRQ.


Flare No. 1, Flare No. 2
Cause: Refinery cooling water tower CT-405 experienced a valve malfunction which resulted in a loss of cooling water to our Naphtha Hydrotreating unit (NHT). Due to the lack of cooling water, our NHT stripper overhead pressure increased and caused PSV-39-235 to relieve to the flare. Simultaneously when the CT-405 valve malfunction, the recirculating cooling water was released from the basin to the ground and flowed offsite.

Followup: No

Recirculating cooling water: 6,000.0 gallons
Sulfur Dioxide: 1,807.0 pounds

FLARE: Sulfur Recovery Unit (SRU)
Cause: Incident involved a release of Sulfur Dioxide during the start up of their 1600 Sulfur Recovery Unit. FLARE.

Followup: No

Notes: BRQ. The facility determined that 157 lbs. of Sulfur Dioxide (RQ. is 500 lbs) was released on 7/7/10, between the hours of 0500 and 0600. The permitted SO2 under EQT 0358 is 300 lb/hr.
Sulfur Dioxide: 621.0 pounds

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.


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.
Hydrogen Sulfide: 192.0 pounds
Volatile Organic Compounds (VOCs): 564.0 pounds
Methane: 927.0 pounds
Ethane: 454.0 pounds

Cause: A higher capacity pump was used on June 17th, the night before the incident, to pump down the level of spent sulfuric acid in the alkylation unit degassing drum to T-50-3 and exceeded the capacity of the tank's thermal oxidizer (TO). When the pressure exceeded the PVRV set point (24 oz/sq inches) the accumulated gases were vented to the atmosphere. Tk50-3

Followup: Yes

Notes: The flow of spent acid from the alkylation unit to T-50-3 was stopped allowing the pressure within the tank to decrease below the set point of the PVRV. The PVRV was subsequently monitored to check that it had completely closed after the pressure decreased to normal levels. Valero identified the following corrective actions: (1) Install downstream flow monitor on spent acid rundown line so operators can monitor the rate of spent acid rundown. (2) Reroute acid pot flush from the degassing drium to the spend acid settler to reduce hydrocarbon carry through. (3) Maintain level in the spent acid degassing drum at 20% or greater when pumping to T-50-3. (4) Set alarm on the spent acid Coriolis meter density to stop or reduce spent acid flow when hydrocarbon carry through appears likely. (5) Evaluate increasing PVRV set pressure from 1/5 psig on T-50-3. (6) Evaluate increasing the size of the TO on T-50-3 to handle additional vapor load.
Sulfur Dioxide: 170.0 pounds
Isobutane: 27,893.0 pounds

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.
Sulfur Dioxide: 12,495.4 pounds
Nitrogen Oxide: 1,215.0 pounds
Volatile Organic Compounds (VOCs): 7,334.2 pounds
Carbon Monoxide: 783.5 pounds
Particulate Matter 10: 100.3 pounds
Benzene: 72.9 pounds
Hydrogen Sulfide: 4,128.5 pounds
Propylene: 21.0 pounds

30 sulfur recovery unit
Cause: On 3/24/11, LDEQ was notified by the Valero St. Charles Refinery that the reportable quantity for sulfur dioxide may have been exceeded during the startup of the 30 Sulfur Recovery Unit. According to the follow-up notification letter submitted by Valero this was a courtesy notification. No reportable quantities were exceeded as a result of this release.

Followup: No

Notes: No Information Given.


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.
Carbon Monoxide: 951.0 pounds
NOx: 102.0 pounds
Particulate Matter: 3.0 pounds
Volatile Organic Compounds (VOCs): 4.0 pounds
Sulfur Dioxide: 12,643.0 pounds
Hydrogen Sulfide: 33.0 pounds

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.
NOx: 139.0 pounds
Carbon Monoxide: 756.0 pounds
Sulfur Dioxide: 3,769.0 pounds
Hydrogen Sulfide: 20.0 pounds
Volatile Organic Compounds (VOCs): 286.0 pounds
Particulate Matter: 5.0 pounds

debutanizer column vent
Cause: 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.

Followup: No

Notes: 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.
Sulfur Dioxide: 290.0 pounds
Propylene: 83.0 pounds

3700 SRU
Cause: On 8/12/14 at approximately 10:30 hrs, the 3700 SRU reaction furnace tripped, which led to a reportable quantity of sulfur dioxide (SO2) from the 3700 TOX. The cause of the trip as a controller logic script that auto initiated and propagated an incorrect flow measurement to the Combustion Air Blowers (K-37-391 A and B). The incorrect flow measurement caused the blower control scheme to falsely assume surge operating conditions and correspondingly the atmospheric discharge vent opened. When the discharge vent opened, it significantly reduced the combustion air flow to the reaction furnace which initiated a Safety Instrumented System trip of the unit.

Followup: No

Notes: Emissions were minimized by transferring SRU feed to other operating trains, until the 3700 SRU was restarted. The following corrective actions were taken: 1) Review the incident with all affected personnel 2) Determine if a two second delay to blower anti-surge logic to accommodate bad flow indication should be programmed into the logic 3) Remove all custom scripts from host computers 4) Update the CSE Change Approval Matrix to include additional QA/QC procedures.
Sulfur Dioxide: 590.2 pounds
Hydrogen Sulfide: 0.3 pounds

1600 SRU Tail Gas Treater Unit
Cause: The refinery experienced an upset in the 3700 sulfur recovery unity (SRU) which resulted in excess SO2 emissions. The 1600 SRU Tail Gas Treater Unit (TGTU) amine regenerator column overflowed sending rich amine to the thermal oxidizer (TOX), which cause it to trip offline. A similar incident occurred in the 3700 SRU. Rich amine from the 3700 SRU regenerator clump overflowed, shutting down both the 3700 SRU inline mixer and TOX. Both the inline mixer and TOX for the 3700 SRU were restarted but tripped offline again. As a result of the malfunctions in the 1600 and 3700 SRUs both were shut down. The remaining sulfur plan feed was routed to the still operating 30 SRU while the feed was cut to all upstream operating process units in order to reduce sulfur loading. The malfunction in the 1600 SRU led to excess SO2 and H2S emissions from the unit's TOX before shutting down. The TOX trip at the 3700 SRU led to excess H2S emissions from the 3700 SRU. Excess feed to the 30 SRY resulting from the shutdown of the 1600 and 3700 SRU led to excess emissions SO2 emissions from the 30 SRU TOX. During the shutdown the TOX tripped offline for short duration periods on multiple occasions which led to excess H2S emissions from the 3700 and 1600 SRUs.


Notes: Emissions were minimized by shutting down the 3700 and 1600 SRUs and reducing feed to upstream operating units. Subsequently, repairing and restarting the 1600 SRU reduced sulfur loading on the 30 SRU, which caused it to resume operation. The limits were exceeded and final calculations are pending and will be reported in a follow- up letter.


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.
Sulfur Dioxide: 6,868.5 pounds
Hydrogen Sulfide: 36.9 pounds
Volatile Organic Compounds (VOCs): 134.9 
Particulate Matter: 0.4 pounds
NOx: 4.6 pounds
Carbon Monoxide: 24.9 pounds

SMR 1 Heater No. 2, 2005-8 (H001 1st Stage Charge Heater), 2005-9 (H002 2nd Stage Charge Heater), 2005-10 (H003 1st Fractionator Charge Heater), 94-GDU (Low SUlfur Gasoline Unit Heater), 2005-1 (crude Heater F-72-704), 2005-2 (Vacuum Heater F-52-02)
Cause: On Febuary 9, 2014, at approximately 18:44 hrs, the lean amine return pump (P-16-204A) tripped offline unexpectedly due to high temperature, which led to flooding of the regenerator column and subsequent downstream amine acid has (AAG) knockout vessels. The AAG knockout vessels reached full capacity, which caused the sulfur recovery units (SRUs) to trip offline. Consequently, we were unable to regenerate our amine used for scrubbing sulfur from refinery fuel gas. As this fuel gas was burned in various process heaters within the refinery, the sulfur was converted and emitted to the atmosphere as SO2. Furthermore, as we recovered from the incident, elevated SO2 emissions were observed during the subsequent startup of the 1600 SRU.

Followup: Yes

Notes: Emissions were minimized by reducing unit throughputs until the SRUs could be restarted. Air monitoring was conducted in the downstream wind direction with no detected SO2 or H2S readings by the handheld monitor. The procedures/measures adopted to prevent recurrence of this accident are two-fold: 1. Review this incident with affected personnel focusing on shutting down the unit when discharge flow cannot be reestablished in a timely manner and consideration for the response time available in lost flow situations (Completed -- 03/12/2014). 2. Develop "what if" scenarios for employees to use (Completed -- 03/01/2014). Hydrogen Sulfide emissions were calculated assuming a 99.5% conversion of SO2 to H2S in process heaters and excluding H2S emissions resulting from Sulfur Recovery Units which were less than permitted H2S emissions for the accident.
Sulfur Dioxide: 9,923.0 pounds
Hydrogen Sulfide: 25.8 pounds