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|LDEQ Accident Number
|Point Source(s)||Notes||Amount of Release|
|Flare 1 and 2||Cause: The wet gas compressor in the delayed coking unit had malfunctioned.|
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.
|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."|
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.
|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.|
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.
|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.|
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.
|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.|
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.
|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.|
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.
|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.|
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.
|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.|
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
|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.|
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.
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