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Valero (26003), Norco

Releases of Hydrogen Sulfide

LDEQ Accident Number
Accident Date
Point Source(s) Notes Amount of Release
82697

2005-10-01
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.
8.0 pounds
82120

2005-09-12
Flare 1 EIQ 15-77; Flare 2 EIQ 12-81
Cause: Loss of power, control valves failed. Power interruption caused by 3rd party electricity provider. Battery back up system damaged when it received a power surge during restart of refinery after Hurricane Katrina.

Followup: Yes

Notes: reduced feed rates to our West Plant
19,400.0 pounds
80318

2005-07-06
Flare 1 EIQ 15-77; Flare 2 EIQ 12-81
Cause: Power failure caused a shut down as a result of tropical storm Cindy.

Followup: Yes

Notes:
76465

2005-01-26
No Information Given
Shutting Down part of refinery
Cause: Shutting Down part of refinery

Followup: No

Notes: Courtesy notice
92308

2006-11-28
Thermal oxidizer
Cause: Thermal oxidizer had lost the flame and there was a possibility of Hydrogen Sulfide exceedance. After review, found BRQ.

Followup: No

Notes: Letter states that emissions were BRQ.
91842

2006-11-03
Thermal oxidizer stack
Cause: Incline mixer for the sulfer recover units' tail gas treating unit malfunctioned. Led to higher Hydrogen Sulfide gas concentrations being send to the TOX causing it to trip. Also, the temperature in the TOX dropped due to both the TOX trip and loss ofheat from the incline mixer. Precise cause of failure is Under Investigation

Followup: Yes

Notes: Restarted the TOX ASAP so that any residual H2S could be combusted. Restarted the TGU as soon as practical to minimize SO2 emissions.
629.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
12.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
4.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
7.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
2.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
5.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
2.0 pounds
87993

2006-05-20
Coker flaring (fire)
Coker flaring (SD)
DHT liquid burnoff
GHT flaring (fire)
KHT flaring (fire)
NHT flaring (fire)
Cause:

Followup: Yes

Notes: Emissions were minimized by shutting down the affected units and the fire was extinguished.
6.0 pounds
100919

2007-11-09
EQT 013 and EQT 007
EQT 013 and EQT 007 (Flares #1, 2)
Cause: The Wet Gas Compressor tripped on low oil pressure.

Followup: Yes

Notes: The incident involved releases on two separate days, 11/09/07 and 11/12/07, but were assigned the same incident Report # by SPOC.
18.0 pounds
100919

2007-11-09
EQT 013 and EQT 007
EQT 013 and EQT 007 (Flares #1, 2)
Cause: The Wet Gas Compressor tripped on low oil pressure.

Followup: Yes

Notes: The incident involved releases on two separate days, 11/09/07 and 11/12/07, but were assigned the same incident Report # by SPOC.
12.0 pounds
99376

2007-09-12
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.
98939

2007-08-27
Thermal Oxidizer
Cause: The Thermal Oxidizer for the Sulfur Recovery unit (that oxidizes Hydrogen Sulfide) tripped, and they struggled to restart it.

Followup: No

Notes: No reportable quantities were exceeded during this incident, so the notification was to be considered a courtesy.
97515

2007-06-29
primary seal: Floating Roof Tank 150-13
Cause: : Operator/s failed in draining the drum to the slop system, as all liquids (rather than just the sour water) were drained and coker gas entered the floating roof rerun tank, T-150-13. The pressurized gas bubbled through the tank carrying slop oil onto the roof and released to the atmosphere.

Followup: Yes

Notes: Gases leaving the tank were dispersed into the atmosphere. Slop oil on the roof was recovered and returned to the process. The roof was cleaned and the coker off gas knock out drum drain valve was closed immediately upon discovery.
625.0 pounds
96323

2007-05-17
Thermal Oxidizer #1 (TOX) and Tail Gas Treating Unit
Cause: The Thermal Oxidizer had tripped and this event might exceed or have exceeded reportable quantities of Sulfure Dioxide. Also, the Tail Gas Treating Unit (TGTU) had tripped and there was a possibility of an Hydrogen Sulfide exceedance.

Followup: Yes

Notes: Restarted the Thermal Oxidizer and the tail gas unit, reset the level set point to compensate the level indicator error, and replaced the faulty level indicator the next day. They have added the level indicator to their monthly preventive maintenance schedule, completed 6/16/2007. **["May 17, 2007 16:00 to 17:00, H2S (lbs/hr) 157.72, permit limit 0.5, TOX Down for 12 minutes (<700F)]
158.0 pounds
93656

2007-02-01
Thermal Oxidizer
Cause: TOX, which oxidizes H2S to SO2, began to malfunction and cause several shutdowns.

Followup: Yes

Notes: During periods of prolonged outages, they reduced the refinery throughput in order to minimize the sulfur load to the TOX.
1,785.0 pounds
93686

2007-02-01
Thermal Oxidizer (TOX)
Cause: TOX, which oxidizes H2S to SO2, began to malfunction and cause several shutdowns.

Followup: Yes

Notes: During periods of prolonged outages, they reduced the refinery throughput in order to minimize the sulfur load to the TOX.
1,785.0 pounds
93265

2007-01-15
Thermal Oxidizer
Cause: The Thermal Oxidizer, that oxidizes Hydrogen Sulfide to Sulfur Dioxide, had tripped.

Followup: No

Notes: Letter states,
111397

2008-12-12
MSCCU Reactor Secondary Cyclone
Cause: pinhole leak on MSCCU Reactor Secondary Cyclone

Followup: No

Notes: Letter states that emission were BRQ.
6.0 pounds
111397

2008-12-12
MSCCU Reactor Secondary Cyclone
Cause: pinhole leak on MSCCU Reactor Secondary Cyclone

Followup: No

Notes: Letter states that emission were BRQ.
6.0 pounds
109755

2008-10-01
Flares 1 and 2
Cause: Hot Separator develops crack allowing material and gases to release.

Followup: No

Notes: Emissions minimized with a controlled shutdown of the unit. Firewater sprayed on to control vapors and mitigate inflammation. Oil absorbent booms deployed. Water collected by vacuum truck from drainage routes.
105151

2008-04-27
CT-04-600 Cooling Tower
Cause: leak on a heat exchanger on the recycle gas cooler in the HTHC

Followup: Yes

Notes: Valero routed gases to the Flare Recovery Syste,
104831

2008-04-17
Flares 1 and 2 (EQT 013 and 007)
Cause: difficulty during startup of catalytic cracker and gas Desulfurization Unit

Followup: No

Notes: Startup rates of units kept low to reduce emissions
103521

2008-02-29
Flare
Cause: while initiating corrective actions for another incident the WGC tripped.

Followup: No

Notes: Emissions minimized by immediately restarting WGC.
21.0 pounds
103290

2008-02-21
Sour Water Stripper Acid Gas Valve
Cause: pinhole leak on MSCCU Reactor Secondary Cyclone

Followup: No

Notes: Letter states that emission were BRQ.
102262

2008-01-13
Flare
Cause: the blow down system off the Wet Gas Compressor was routed to flare to relieve coke drum pressure after one of the coke drums cracks.

Followup: No

Notes: Letter states that emission were BRQ.
2.0 pounds
102201

2008-01-10
Flare Gas Recovery Compressor
Cause: Flare Gas Recovery Compressor tripped

Followup: No

Notes: Letter states that emission were BRQ.
1.0 pounds
102102

2008-01-06
Coker Wet Gas Compressor
Flares 1 and 2
Cause: failure of WGC

Followup: No

Notes: DEQ report states that there have been many WGC failures, enough that they have made repeated calls to the facility urging them to repair the unit to prevent recurrence of such events. According to report, Valero has repaired the WGC.
19.0 pounds
102089

2008-01-05
Thermal Oxidizer #1 (EQT 195 (99-3))
Cause: TOX 1 for SRU tripped

Followup: No

Notes: Repeated attempts to rebuild the igniter and restart the THOX
460.0 pounds
102086

2008-01-03
Flares 1 and 2
Cause: Guardian over speed device malfunction causes WGC to trip

Followup: No

Notes: Emissions minimized by immediately restarting WGC. A series of follow-up reports reveal that Valero did not know age or maintenance history of WGC upon purchase of facility from Orion. Valero has now replaced major components of WGC and plans to replacethe guardian over speed device next.
16.0 pounds
118541

2009-10-07
Fare 1, Flare 2
Cause: The MSCCU Wet Gas Compressors tripped offline due to a malfunction of their electric and controls systems. Wet gases were relieved through pressure control valves to Flares 1 and 2 in order to maintain safe system pressure.

Followup: Yes

Notes: Wet gas compressor was restarted.
6.0 pounds
116930

2009-07-30
No information given
No information given.
Cause: Emissions were detected during the start up procedures of refinery process units between 7/30/09 and 8/03/09. Follow up report determined releases were all below reportable quantities and did not give any more information.

Followup: Yes

Notes: Feed was pulled from malfunctioning units.
116428

2009-07-12
#3 Debutanizer Reflux pump
Cause: At approximately 1:15 operators noticed that the #3 Debutanizer Reflux pump seal had failed and was releasing process gases ti the atmosphere. Seal failure was caused by a failure in the pump's thrust bearing.

Followup: Yes

Notes: Deluge water was used to contain the vapors and reduce the risk of fire. The malfunctioning pump was isolated and shut down. A redundant backup pump was started to avoid unit shutdown. Reflux pump thrust bearings will be replaced from 40 degree contact bearings to 15 degree contact bearings.
324.0 pounds
115395

2009-07-02
Flares 1, Flare 2
Cause: While performing a preventative maintenance check. While checking voltage output levels on the power supplies in the control cabinets an arc was created that shut down both power supply #1 an #2. The loss of both power supplies caused the redundant controllers to power down, which shutdown the Coker Wet Gas Compressor sending material to the flare.

Followup: Yes

Notes: Wet gas compressor was immediately restarted
11.3 pounds
115515

2009-06-09
Fire
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.
91.0 pounds
115515

2009-06-09
Fire
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.
13.0 pounds
128357

2010-12-27
FLARE: flare #1 & #2
Cause: Wet gas compressor (WGC) in the delayed coking unit malfunctioned resulting in SO2 emissions to Flares #1 and #2. A level indicator on the coker tower HCGO tray malfunctioned. FLARE.

Followup: Yes

Notes: RQ. Reportable quantities for sulfur dioxide were exceeded. See Root Cause Analysis for more information. DLEQ report, Refinery letter, and follow-up letter all included in file.
12.0 pounds
123734

2010-05-25
FLARE: MSCCU
Cause: Small hole in Milli-Second Catalytic Cracking Unit (MSCCU)--had to flare when shutting down for repair. FLARE.

Followup: No

Notes: BRQ. Refinery letter states that no reportable quantities were exceeded. No information given regarding remedial actions.
21.0 pounds
122464

2010-03-30
FLARE: flare #1
Cause: Elevated sulfur compounds at Flare #1. FLARE.

Followup: Yes

Notes: Ongoing testing/monitoring of elevated sulfur compounds in the flare during the week. Unclear if emissions had ceased at time of LDEQ report.
121805

2010-02-27
FLARE: Flare #1 & #2, MSSCU, SRU, 3700 TOX
Cause: Flaring caused by difficulty starting up the Millisecond Catalytic Cracking Unit (MSCCU), as well as the Sulfur Recovery Unit (SRU) and its related thermal oxidizer (TOX) after a maintenance shutdown. Some emissions exceeded visible emissions and opacity permit limits as well.

Followup: Yes

Notes: RQ. Refinery letter states that reportable quantities were exceeded for sulfur dioxide, nitrogen oxide, and hydrogen sulfide. Initial refinery letter, plus two additional follow-up reports included in file. Remedial actions: "Maximized steam to flares to mitigation visible emissions...and adjusted feed rates and other process parameters in order to complete startup and stabilize the MSCCU and 3700 SRU units." "A minimal amount of waste gas is expected to be flared during process startup. Currently this activity is permitted for expected losses of criteria pollutants and hydrogen sulfide. Since the loss of propylene is not permitted under startup emissions, but is expected, Valero will request propylene allowances in a future application for a permit modifications. Additionally, we are planning to install flare gas recovery compressors on Flares 1 and 2 in the year 2011. These compressors will have the ability to capture waste gasses generated from startup activities and return them to the refinery fuel gas system."
613.0 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.
133803

2011-09-04
3700 and 30 SRU
Cause: The sulfur dioxide levels at 3700 and 30 unit thermal oxidizers were elevated due to failure of a pressure transmitter on the 3700 unit overhead accumulator. Valero estimated that the RQ for sulfur dioxide was exceeded at approximately 1:10 am and the RQ for hydrogen sulfide was not exceeded. The failing transmitter gave false indications in both the overhead accumulator pressure and the stripper overhead pressure. This prompted operational moves in the unit to shift loads in an effort to return the SRUs to stead operation.

Followup: Yes

Notes: After the local pressure gauges in the field were verified, it was determined that a single pressure indication was malfunctioning and operational moves were made to restore normal operating conditions. The following corrective actions were identified to prevent recurrence of this incident: (1)Repair both the overhead accumulator and the stripper overhead pressure transmitters and have separate pressure readings on the DCS. (2)Revise the DCS page to reflect both pressure indications. (3) Ensure the DCS and logic changes are covered by the management of change (MOC) process. (4) Conduct training with Operators on this incident. (5)Have the pressure control valve 37-4182-A inspected during the 2014 turnaround.
133142

2011-08-17
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.
192.0 pounds
131415

2011-05-20
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.

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.
4,128.5 pounds
130948

2011-05-02
Coker LPG line
Cause: Valero had blinded and de-inventoried the Coke LPG line as part of a project to elevate the Prospect Road pipe bridge that connects their East Plant and West Plant. The blinds were removed several days prior to the incident but valves in the pipe system remained closed. Valero believes that gas leaked by one of the valves and accumulated in a section of pipe after the blind had been removed on the West Plant side of the project area thus trapping gas between two closed valves. On the day of the incident, the project operator opened the downstream valve in the pipe bridge that was closest to the FCCU in order to commission a new section of pipe; the upstream valve remained. When the valve was cracked open, gas that had accumulated in the pipe leaked out into the FCCU which was undergoing construction at the time of the incident.

Followup: Yes

Notes: Coker liquified petroleum gas (LPG) which is composed mainly of butenes and propenes was released from pipe openings in the FCCU area and dispersed. Emissions were minimized by isolating the coker LPG line. Valero identified the following corrective actions and target completion dates were identified as a result of the root cause failure analysis of this incident: (1) Issue safety alert on this incident to all personnel (2) Review incident with operators and discuss need for good communications when lining up piping to units (3) Develop a battery limits blind list for the FCCU for use during future turnarounds (4) Develop a battery limits list for Complex III (Crude-Vacuum-Coker units) for use during future turnarounds
38.7 pounds
129748

2011-03-06
CCU Flange
Cause: On 3/6/11 at approximately 6:04pm, Mr. Charles Knock of Valero made notification that two contract employees working in the catalytic cracking unit (CCU) during maintenance availability had been exposed to hydrogen sulfide. In addition to the exposure, contractors also sustained other injuries related to falling and were hospitalized. Trooper Sparks met with Valero representatives on the day of the incident. State Police and Occupational, Safety, and Health Administration (OSHA) officials have met with Valero representatives as part of the ongoing investigation into the cause of this event. It appears that the contractors were exposed to hydrogen sulfide escaping from an improperly installed blind during steaming of the line.

Followup: No

Notes: The discharge was detected at 3/6/11 at 3:00pm. Affected workers were transported to area hospitals at approximately 3:35 pm. The leaking piping system was secured approximately 93 hours later and during that time no appreciable quantities of hydrogen sulfide were measured. Hydrogen sulfide dispersed into the atmosphere. Measured hydrogen sulfide in the vicinity of the incident revealed that the concentrations in the air were substantially dissipated prior to leaving the process unit and posed no threat to the public. Work in the immediate area was stopped while an investigation was conducted to identify the source of the hydrogen sulfide. When the source was identified, he defectively installed blind was replaced under observation by the State Police. Monitoring was conducted to confirm that the replacement blind was not leaking. Measures to prevent recurrence will be identified as part of a pending investigation. There were two injuries from this incident, one of which resulted in a fatality. State officials are investigating the fatality to determine the cause of death. The second injured person was treated at an area hospital and released.
30.0 pounds
144411

2012-11-05
Flare 1 and 2
Cause: The wet gas compressor in the delayed coking unit had malfunctioned.

Followup: Yes

Notes: The maximum hourly permitted emissions for hydrogen sulfide and sulfur dioxide exceeded the maximum hourly permitted emissions. Gas from the coker was combusted in Flare 1 and Flare 2. The resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. The incident will be communicated to all affected personnel. The XY-53325 A and B solenoids as well as the XY-53325A relay will be replaced during the text outage. Wiring in the compressor control cabinet will be upgraded to separate critical wiring from general purpose wiring.
8.0 pounds
142968

2012-09-13
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.
33.0 pounds
143284

2012-09-13
Tail gas incinerator on the 3700 sulfur recovery unit
Cause: Malfunction of the tail gas incinerator on the 3700 sulfur recovery unit caused the release of 29 pounds of hydrogen sulfide gas.

Followup: No

Notes: Initial correspondence between the refinery and Louisiana DEQ indicate an original estimate of a release of 100 pounds of hydrogen sulfide, which was later corrected as 29 pounds of hydrogen sulfide (below the reportable quantity).
29.0 pounds
141595

2012-07-27
wet gas compressor
Cause: The wet gas compressor in the delayed coking unit malfunctioned resulting in excess H2S and SO2 emissions at Flares 1 and 2.

Followup: Yes

Notes: On the day of the incident, the steam control valve that regulated the turbine speed for the Coker WGC to account for increased gas flow rates due to an upstream process upset. When this upset was corrected, the gas flow to the WGC decreased and operators began closing the steam control valve for the steam turbine to reduce the speed of the WGC due to this lower gas flow. However, the steam control valve did not provide adequate response and did not result in a change in turbine speed. The WGC ultimately shutdown when the turbine reached its protective overspeed trip point and stopped all steam flow to the turbine. This happened very quickly and no further adjustments to the steam control valve before the turbine tripped. Emissions were minimized by restarting the wet gas compressor. This incident will be communicated to all affected personnel. The facility will install a control clamp at 80% on the steam control valve output to prevent a delayed control response due a dead band on the valve. A team will also be created from operations, controls, process, and reliability to monitor and record events in the Trilogger and review with the process control design team on a biweekly basis to control performance and tune as necessary. There is a discrepancy regarding the incident date. The subject lists the incident date as 07/27/2012, while the written notification states that it occurred on June 27, 2012.
17.0 pounds
140457

2012-06-13
wet gas compressor
Cause: The Wet Gas Compressor malfunctioned when operators were warming Coke Drum D. Shortly after switching to Coke Drum D, pressure on the unit spiked and the Fractionator overhead became overloaded. The temperature increased 20 degrees and caused the Interstage drum to become overwhelmed with condensing liquid. The compressor tripped on high interstage level resulting in flaring.

Followup: Yes

Notes: As a result of this incident, the maximum hourly combined permitted emissions for H2S and SO2 were exceeded as well as the reportable quantity. Emissions were minimized by restarting the wet gas compressor. The facility will now hold an operations stand down with each shift to review the incident and stress the importance of following all standard operating procedures. The facility is also adding a line to the console check sheet to verify that the tap water is blocked in before warming up drums prior to switching drums.
3.0 pounds
140250

2012-06-05
wet gas compressor
Cause: The wet gas compressor in the delayed coking unit malfunctioned resulting in excess H2S and SO2 emissions at Flares 1 and 2.

Followup: No

Notes: Gas from the coker was combusted in flare 1 and flare 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. The incident is still under investigation. No procedures or preventative measures have been identified at this time.
3.0 pounds
140047

2012-05-26
wet gas compressor
Cause: The wet gas compressor in the delayed coking unit had malfunctioned resulting in excess SO2 emissions at flares 1 and 2.

Followup: Yes

Notes: Gas from coker was combusted in Flare 1 and Flare 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. This incident is still under investigation. No procedures or preventative measures have been identified at this time. A "30 day follow up report" was submitted on February 28, 2013 citing that the root cause failure analysis report had been submitted for the incident. The document only lists 3 actions Valero plans on taking: "1. We will communicate this incident to all affected personnel. 2. Operations will implement a guidance document to reduce set points by 15 degrees Fahrenheit on loss of LCO charge heater. 3. Improve cracking beds operation stability by limiting the temperature delta. Add a high priority alarm to the DCS." The February 28th letter does not provide the root cause of the accident.
3.0 pounds
139226

2012-04-30
Wet gas compressor
Cause: The Wet Gas Compressor in the delayed coking unit at Valero St. Charles Refinery malfunctioned resulting in excess SO2 emissions at flares 1 and 2.

Followup:

Notes: Refinery fuel gas was combusted in Flare 1 and Flare 2 and the resulting combustion byproducts rapidly dispersed. Emissions were minimized by restarting the wet gas compressor. This incident is still under investigation. No procedures or preventative measures have been identified at this time.
2.0 pounds
138677

2012-04-08
No information given
Cause: The 1600 Sulfur Recovery Unit (16 SRU) tripped and went offline for about 2.5 hours. It is suspected that SO2 and H2S levels were elevated at the associated thermal oxidizer (1600 TOX-EQT241). The exact cause is under investigation.

Followup: Yes

Notes: These emissions will be reported in the Refineries Title V permit compliance reports. In the first written follow up report, it is suspected that the rate and reportable quantities of SO2 and H2S were exceeded. The SO2 concentration limit may have also been exceeded. The opacity standard may have been exceeded for 2 hours and 34 minutes. In the follow up report sent May 3, 2012, the values were calculated as below reportable quantity.
25.0 pounds
152289

2013-11-11
Flare 1
Cause: 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.

Followup: Yes

Notes: 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.
12.0 pounds
151623

2013-10-14
1600 Sulfur Recovery Unit
Cause: 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.

Followup:

Notes: 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.
0.3 pounds
150290

2013-08-09
6d 14hr 24m
Coker No. 2 Steam Vent
Flares 1,2,3,4&5
Flares 1,2,3,4&5; 30, 1600, & 3700 TOX; FCCU; GDU; Boilers B-401C, B-401D, & 401-E
Flares 1,2,3,4&5; 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; FCCU; GDU; Boiler B-401C, B-401D, & 401-E
Flares 1,2,3,4&5; FCCU; GDU; Boilers B-401C & B-401D
Flares 1,2,4&5; 30, 1600, & 3700 TOX; Coker No. 2 Steam Vent
Flares 1,2,4&5; Coker no. 2 Steam Vent
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.
652.0 pounds
149758

2013-07-17
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.
20.0 pounds
148110

2013-04-14
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.

Followup: Yes

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
144.0 pounds
146729

2013-02-19
Flares 1, 2, 3, and 4
Cause: 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.

Followup: Yes

Notes: 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".
4.1 pounds
146196

2013-01-21
Flare 1 and 2
Cause: 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.

Followup: Yes

Notes: 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.
14.8 pounds
159934

2014-11-09
Hydrocracker-Hydrotreater
Cause: On 11/9/14 at approximately 21:30 hours, the Hydrotreater-Hydrocracker (HTHC) Recycle Compressor malfunctioned, which initiated a shutdown of HTHC and led to a reportable quantity of sulfur dioxide. The cause of the malfunction is under investigation.

Followup: No

Notes: Emissions were minimized by shutting down and then restarting the HTHC unit. Air monitoring was conducted in the downstream wind direction within and around the refinery. The incident is still under investigation to determine preventative measures.
8.6 pounds
158089

2014-08-15
3h 6m
Cause: On August 15, 2014, electrical feed from a power substation tripped offline, causing multiple units to shutdown. An investigation of the incident found the cause to be the failure of a sudden pressure relay on transformer T-3 at the PS-2 substation. This provided a false trip input into the transformer differential relay. The relay logic reacted to the input by isolating the transformer, thus de-energizing power to Buss 3, which shut down several pieces of equipment. Maximum hourly permitted emissions rates for sulfur dioxide, hydrogen sulfide and volatile organic compounds from Flare 1 were exceeded. Neither report includes emissions totals for hydrogen sulfide.

Followup: Yes

Notes: At the time of the accident, Valero energized an alternate source of power to supply the equipment. The Diesel Hydrotreater (DHT), Naptha Hydrotreater (NHT), and Continuous Catalytic Reformer (CCR) Units tripped off-line. Valero left them down until reliable power was restored. The FCCU and Crude Units reduced rates to minimize emissions. Flare gas recovery remained in operation to recover some of the gases sent to the flare header. A Root Cause Analysis identified several corrective actions to be taken by Valero, including: 1) Communicate the incident to affected personnel (Estimated completion date: 10/31/14), 2) Work with Electrical Safety and Reliability network (ESARN) to develop a recommendation for routine testing/inspection of sudden pressure relays on transformers(Estimated completion date: 12/31/14), 3) Develop a list of refinery substations that would benefit from MAIN-TIE-MAIN auto transfer scheme and prioritize implementation (Estimated completion date: 12/31/14), 4) Review the power source for refinery analyzers and develop a prioritized list of analyzers that would benefit from moving from a Purchased Power source to a UPS source (Estimated completion date: 12/31/14), 5) Develop a written guideline for restorations of power for the refinery following power loss scenarios at Prospect and Good Hope Substations (estimated completion date: 12/31/14).
157998

2014-08-12
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.
0.3 pounds
157325

2014-07-09
EQT 0360 Flare No. 4
Cause: The Hydrotreater/Hydrocracker (HTHC) recycle compressor malfunctioned, which initiated a shutdown of the HTHC and led to a reportable quantity of sulfur dioxide. The cause of the malfunction is under investigation while the unit is being repaired. Permitted emissions for H2S, VOC and SO2 was exceeded for 1 hour. The unit depressured in approximately 15 minutes, however, due to the excess production of hydrogen following the HTHC shutdown, Valero continued to flare hydrogen. Valero submitted a Notification of Case by Case insignificant activity on July 11, 2014 to cover emissions from Hydrogen flaring; therefore, hydrogen flaring was not considered within the duration of this event. Valero exceeded hourly permitted emissions for hydrogen sulfide, volatile organic compounds and sulfur dioxide at Flare 4 for one hour.

Followup: Yes

Notes: Shutdown of HTHC unit. Air monitoring was conducted downwind of the refinery. No procedures or preventive measures given at the time of the report. Follow up report lists the following measures identified to prevent recurrence: 1) Review this incident with affected personnel and attach sign off sheet 2) Investigate installing knock out put upstream on dry gas seal (DGS) panel inlet filters with continuous blowdown 3) Investigate the need for level indication and drains on the make-up gas (MUG) discharge pulsation dampers 4) Use recycle gas to supply panel when sufficient differential pressure is available and modify procedures accordingly 5) Evaluate the functionality of the TriLogger system and determine if upgrades are needed 6) Review the lubrication program for HTHC compressors 7) Run drain lines from the dry gas seal panel filters to a safe location for liquid removal
8.6 pounds
157159

2014-07-01
3700 Sulfur Recover Unit
Cause: The 3700 Sulfur Recover Unit (SRU) furnace main air safety shutdown valve closed unexpectedly, which initiated a 3700 SRU trip and led to excess emissions of sulfur dioxide. While troubleshooting the malfunction, operators shifted the amine acid gas feed (AAG) from 3700 SRU to two remaining units (1600 and 30 SRU). The move caused excess emissions from the 30 SRU while stabilization was in process. About 30 minutes later, the malfunctioning valve reopened, reintroducing AAG into SRU 3700 and causing a RQ emission for sulfur dioxide. Later in the same day, at approximately 20:45 the 3700 SRU reaction furnace main air safety shutdown valve closed again. After the second malfunction, Valero purposely shut down the 3700 SRU in order to further troubleshoot the issue, and then implemented sulfur shedding in order to reduce sulfur loading to the SRUs. Sulfur shedding included: decreasing throughput of the Hydro-Treater, Hydro-Cracker (HTHC) unit to minimum rates, reducing overall refinery crude throughput, shifting amine acid gas feed to the two remaining operating SRUs (1600 and 30 SRUs), and shutting down sour water acid gas feed (SWAG) to the remaining two SRUs. The quick shift in AAG feed to the remaining two SRUs resulted in excess emissions from the 30 and 1600 SRUs for approximately 1 hour while making the necessary adjustments for the increased AAG loading to the units. The additional loading at the 30 SRU caused the 30 Thermal Oxidizer (TOX) to trip offline at 21:52 hrs due to low oxygen for combustion. It was brought back online at approximately 23:32. However, during the outage Valero experienced elevated hydrogen sulfide emissions from the 30 TOX. When the 30 TOX tripped, they had trouble restarting it due to wires that were found to be corroded and detached from the terminated position. The wire was tied to a system that was needed to complete the logic to start the TOX. The corroded wires were repaired, the termination box was properly sealed and the TOX was restarted. An investigation into the SRU 3700 reaction furnace main air safety shutdown valve malfunction revealed a loose wire as the cause. Valero repaired it, restarted the 3700 SRU, and resumed normal operation.

Followup: Yes

Notes: Emissions were minimized by shutting down the 3700 and reducing the feed to upstream operating units. Subsequently, repairing and restarting the 3700 SRU reduced sulfur loading on the 30 and 1600 SRU, which allowed those units to resume normal operation. Air monitoring was conducted in the downstream wind direction within and around the refinery, and no detectable SO2 or H2S was found using portable air monitoring equipment. The following corrective actions were identified: 1) Review the incident with all affected personnel 2) Review the requirement to evaluate the condition of the sealing system of any instrument enclosure that is opened while performing any maintenance task associated with routine or preventative maintenance 3) Remove the logic for the 30 SRU atomizing stream valve from the purge permissive and pilot permissive.
0.1 pounds
156618

2014-06-09
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.

Followup:

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.
155696

2014-05-01
Treatment pond
Cause: Upon receiving an odor complaint an SPO contact found the treatment pond on the southeast side of the Valero facility had elevated levels of H2S. However, no limits were exceeded.

Followup: No

Notes: There is no information to the cause of the odor nor the duration only that the incident has been closed.
155645

2014-04-30
Flare 1
Flares 1, 2, 3
Cause: The fluid cat cracking unit (FCCU) wet gas compressor shut down due to a loss of power that resulted from a transformer short circuit and a circuit breaker malfunction. As a result, flaring occurred from permitted flares 1, 2 and 3. Workers reduced total feed and reactor temperature in the FCCU to minimize flaring until compressors could be restarted. Transformer failed in the EP-03A substation. A relay setting associated with this system was not set properly and allowed the fault current to reach the Good Hope Substation. The fault was cleared by the breaker at the Good Hope Substation. As a result, several other transformers also tripped and upset the FCCU. This accident exceeded maximum hourly permitted emissions for sulfur dioxide, hydrogen sulfide, hexane, and Volatile Organic Compounds at Flare 1 for one hour. Maximum hourly permitted emissions were also exceeded for NOx and carbon monoxide at Flare 2 for one hour. Maximum hourly permitted emissions for sulfur dioxide and Volatile Organic Compounds at Flare 2 for 5 hours. Reportable quantities for sulfur dioxide and propylene were exceeded.

Followup: Yes

Notes: At the time of the accident, emissions were minimized by reducing the overall rate to the unit and reactor temperature. Operators responded by adjusting the power distribution system in order to reestablish the poewr source and restart the compressors. Throughout the event, the Flare Gas Recovery Unit remained in operation to reduce the amount of flared gas. Process changes have been implemented as corrective actions. These include: - updated relay settings - refinery arch flash study and relay setting review - even distribution of four P82-808 pumps across the electrical feed buses - modify MOC checklist to include relay settings and coordination curves - modify PSSR checklist to include relay settings and coordination curves - require all new or changed relay setting requested through CSE with relay setting/coordination curve request form - communicate incident to affected personnel - communicate incident and path forward to CSE electrical engineers, MP electrical engineers and maintenance electrical supervision
8.8 pounds
155480

2014-04-23
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.
36.9 pounds
153767

2014-02-09
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.
25.8 pounds
153607

2014-01-29
Flares 1 and 2
Cause: On January 29, 2014, the Valero St. Charles Refinery (Valero) experienced flaring when the pressure on the Naphtha Surge Drum and the Wet Gas Compressor (WGC) Interstage Drum increased. The pressure controller on the Naphtha Surge Drum malfunctioned due to cold temperatures, which caused the level to rise in the drum. As a result, the level in the Compressor Interstage Drum, which is downstream of the Naphtha Surge Drum, increased and caused the WGC to trip. The pressure controller on the Naphtha Surge Drum was bypassed to the flare header in order to control high levels on additional upstream and downstream vessels with the unit. Flaring stopped after the level in the Compressor Interstage Drum was decreased and the WGC was restarted. Temperatures were below 30degF on the morning of the incident. It was found that the steam tracing on the pressure controller on the naphtha surge drum was not in contact with the valve and insulation blankets were not in place. The lack of steam tracing and insulation exposed the valve to cold temperatures, which caused it to malfunction.

Followup: Yes

Notes: The event was secured by reducing the level in the compressor interstage drum and restarting the WGC. Additionally, the Flare Gas Recovery Unit remained in operation to reduce the amount of flared gas. The following corrective measures have been identified to prevent recurrence: 1. Review this incident with affected personnel. 2. Review and revise as need the freeze protection guidelines. 3-7. Create a pre-winter checklist to identify and correct tracing and insulation issues for Complexes I-V. 8. Repair the steam tracing and insulation for PCV-53-471, LV-53-472, LV-53-020, and LV-53-038. The Reportable Quantity for SO2 was exceeded.
31.0 pounds