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|LDEQ Accident Number
|Point Source(s)||Notes||Amount of Release|
|North Flare (EIQ No. 83-74)||Cause: The regenerate stream from the Unit 28 Butane Isomerization Liquid Feed Drier was inadvertently blocked in. The Liquid Feed Drier then over-pressured and released to the flare.|
Notes: The rundown line was opened up and the regenerate was routed to the Tank Farm to lower the pressure of the Liquid Feed Drier. This incident is currently under investigation.
|South Flare (EIQ No. 69-74)||Cause: Control logic for Unit 47 Amine Unit's Lean Amine Pump was inadvertently tripped during maintenance. Human error caused this release.|
Notes: Valve was closed within a minute of its opening.
|No LDEQ Reported|
|Thermal Oxidizer Cap (no EPN)||Cause: Liquid hydrocarbon carry-over entered the Unit 45 Thermal Oxidizer.
Notes: Operational adjustments made; currently under investigation
South Flare (EQI No. 69-74/EQT 160)
|Cause: The Absorber Reboiler was leaking hot gas into the Hot Oil Surge Drum causing it to overpressure.|
Notes: BELOW REPORTABLE QUANTITY.
|flaring from fuel gas mix drum|
Flaring from Unit 21 Absorber and North Flare (EQI No. 83-74/EQT 162)
|Cause: Shell, Norco, had an unexpected shutdown of one of their units which processes Marathon Petroleum Company off gas, MPC had to flare excess off-gas/ fuel gas during this time.|
Notes: BELOW REPORTABLE QUANTITY.
The North Flare (EIQ No. 83-74/EQT 162)
|Cause: The uninterpretable power supply failed, causing a shutdown of the FCC unit.|
|Flange near the Crude Bottoms Pump in the Crude Unit|
Flange near the Crude Bottoms Pump in the Crude Unity
|Cause: While preparing the Crude Unit for Turnaround activities a fire occurred. It is assumed that the bolts on the flange of a crude pump opened and products was released. The exact cause is still under investigation, but it is assumed that one of the isolation valves were leaking.|
Notes: MPC assumed the entire amount of the sulfur present was combusted even though there was substantial product left on the cement of the unit.
|Unit 34 termal oxidizer|
Unit 34 thermal oxidizer
|Cause: The Amine Unit 47 shutdown when amine circulation was lost because of a control valve failing to close.|
Notes: The shutdown of Unit 45 Sulfur Recover unit reduced the acid gas (hydrogen sulfide-H2S) processing capacity by 1/3. To reduce the acid gas Marathon implemented "sulfur shedding procedures", involving reducing feed desulfurization units and the Coker . A manual bypass valve was opened to restore circulation. Sulfur dioxide limit (250 ppm) on Unit 34 thermal oxidizer and hydrogen sulfide limit 160ppm on the fuel gas system were exceeded.
|South Flare||Cause: Shell off gas compressors had to shutdown and gas was put into the fuel gas system. Fuel gas system overpressured and relieved to flare.|
Notes: Claims emission was below RQ.
|North Flare||Cause: The Crude Overhead Compressor overpressured and was relieved to the North Flare|
Notes: Claims emission was below RQ. Installing pressure indicators on the first stages of both overhead compressors which will be routed to the control room for iproved monitoring.
|FCCO Cooling Tower and the North Flare||Cause: The PGC Aftercooler trim cooler was found leaking hydrocarbons into the FCCO cooling tower.|
Notes: Claims emission was below RQ.
|North Flare||Cause: Fuse was blown causing FCCU to shut down|
Notes: Claims emission was below RQ. Hydrocarbon contains 9 pounds of highly reactive hydrocarbons.
|North Flare||Cause: Scheduled drum swap caused Drum 1 to pressure up. The relief valve on the Fractionator Overhead line relieved to the flare.|
Notes: Claims emission was below RQ.
|South Flare||Cause: Electrical failure caused change in valve position to emergency "dump" on the Gas Oil Hydrotreating unit.|
Notes: Claims emission was below RQ.
|South Flare||Cause: Electrical failure caused change in valve position to emergency "dump" on the Gas Oil Hydrotreating unit.|
Notes: Claims emission was below RQ.
|South Flare||Cause: Compressors in Unit 22 Sturates Gas Plant shutdown for maintenance and gas feed to Unit decreased. As a result temperature of gas feed cooler effluent decreased in turn increasing amount condensed.|
Notes: Claims emission was below RQ. Claims alternative (shutting down the compressor and a subsequent Unit shutdown) would have allowed for a more substantial release of emissions to the environment.
|North Flare and Heater/Boiler CAP||Cause: Recycle compressors shutdown in the Gasoline Desulfurization Unit|
Notes: Stopped hydrocarbon carryover to Amine Scrubber which reduced pressure in the Amine Flash Drum.
|South Flare||Cause: Two steam boilers shutdown unexpectedly causing steam pressure facility wide to drop. The Crude Unit experienced an upset due to the loss of steam pressure and flared off of the Splitter Overhead receiver.|
Notes: No Information Given. DEQ claims emission was below RQ.
|Gas Oil Hydrotreating Unit||Cause: While the unit was starting up, a crack was noticed. Cause of crack is under investigation.|
Notes: Claims emission was below RQ. No Information Given
North Flare (EQT162 / EIQ 83-70)
|Cause: FCCU shutdown due to an unknown failure in the unit's Wet Gas Compressor.|
Notes: Motor associated with the WGC was replaced.
|FCCU Tubing||Cause: Tubing from a flow orifice plate broke off and released LPG.|
Notes: Unit start-up was aborted, all fired sources were extinguished and a fire monitor was opened.
|North Flare (EQT162 / EIQ 83-70)||Cause: Wiring issue in Wet Gas Compressor causes FCCU shutdown.|
Notes: Report states that shutdown is permitted twice annually, so all emission are permitted. No info on which pollutants were released or the amounts.
North Flare (EQT162 / EIQ 83-70)
|Cause: A drain valve plugged causing the Fractionator in the Coker Unit to overpressure. This caused the Unit's compressor suction drum to relieve to the North Flare|
Notes: Operations manually closed the first-stage spillback on the compressor which limited the flaring event.
|North Flare (EQT162 / EIQ 83-70)||Cause: A partial refinery-wide power failure occurred. This caused several units to shutdown and relieve to flare. A small exchanger fire also occurred.|
Notes: Once maintenance personnel secured the power supply, Operations began bringing units back on line. Follow up report with same DEQ incident number lists different emission amounts.
|North Flare (EQT162 / EIQ 83-70)||Cause: Coker Unit's Wet Gas Compressor shut down due to high level in the suction drum|
Notes: Pending results of investigation
|Cause: A valve misalignment on the iso-butane pump allowed iso-butane to be routed to the flare for approximately six hours before being discovered.
While troubleshooting the flaring incident, operations found the relief valve on th DHT unit's recycle gas scrubber "chatter" to the flare. during the investigation it was discovered that the newly installed valve had malfunctioned|
Notes: none, the releases went unnoticed until later.
|FCC Unit 205||Cause: Due to an unexpected loss of power to the control system of the Unit 25 FCCU. FCCU shut down as designed which resulted in less gas feed to the Unit 205 Coker. This decreased in feed caused the Coker Wet Gas Compressor Suction Drum to briefly exceed the maximum safe operating pressure of the drum which resulted in the Coker Wet Gas relieving tot he ground flare. There was no known offsite impacts resulting from this incident. The emissions from the FCCU shut down are permitted as part of the overall North Flare. Compressor spillback opened rapidly to compensate and a high pressure was reached on the suction drum. Pressure control valve opened to flare once pressure reached 21 psig.|
Notes: The FCCU was safely shut down and all other related unit feed rates were adjusted per the FCCU shutdown plan. The Coker Unit Wet Gas Compressor control system compensated for the increased suction pressure by increasing the compressor speed. All aspects of this incident are currently under investigation.
|FLARE: Unit 59 South Flare||Cause: Refinery letter states that an unexpected change in the feed composition caused an over-pressurization of the high pressure stripper column. This resulted in the opening of the process safety valve to relieve pressure within the column. FLARE.|
Notes: RQ. Reportable quantities for sulfur dioxide were exceeded. Changes were made in Unit 15 to compensate for the increase in pressure in the high pressure column.
|FLARE - Unit 59 North Flare [EQT0162, EIQ83-74]; Unit 05||Cause: "Due to instrumentation malfunction, the inlet valve on the Unit 05 Coker Wet Gas Compressor Suction Drum closed. The compressor shut down and the material was routed to the North Flare. FLARE.|
Notes: RQ. The reportable quantity for sulfur dioxide was exceeded during this incident. Detailed emissions report included. Inlet valve on Unit 50 was opened, the compressor was restarted, and material was routed to the compressor. No additional information given.
|FLARE - North [EQT282] & South Ground Flare [EQT160]||Cause: "Due to a power failure, the Shell off-gas compressors shutdown causing Marathon to have an over abundance of fuel gas which required flaring as a safety precaution." FLARE.|
Notes: BRQ. Refinery letter states that no reportable quantities were exceeded; detailed emissions report included. No LDEQ report. Refinery follow-up report only; follow-up letter states that original written report was submitted to LDEQ on 9/17/2010, but this is not included in the file.
|FLARE: Unit 59 North (EQT #0162 EIQ #83-74) & South Flares (EQT #0160 EIQ #69-74)||Cause: Refinery letter states that liquid material from the refinery's FCCU carried over into the fuel gas system, causing incomplete combustion in the refinery's process heater and flares.|
Notes: The source of the liquid stream was identified and isolated from the fuel gas system. The remaining liquid was drained from the process units' knockout drums. The process heaters were then restarted. Steps to prevent a recurrence of the incident will be taken once the root cause analysis is completed. NOTES: Nitrogen Oxides were released.
|FLARE - North Ground Flare||Cause: Instrument malfunction in the Hydrocracking Unit caused liquid material to be routed to the GME Crude Unit overhead gas system, compressor shut down, routed to flare until liquid was drained. FLARE.|
Notes: RQ. Exceeded reportable quantities during this incident; detailed emissions report included. Technicians troubleshooting malfunction.
|FLARE: coke drum overhead line; 205-PC-1511-V2; north flare||Cause: Water from the offline coke drum overhead line was inadvertently sent to the Main Fractionator, vaporized and overpressured the wet gas compressor suction drum causing 205-PC-1511-V2 to open to the North Ground Flare. Released into air. FLARE.|
Notes: RQ. 2548 lbs of Sulfur Dioxide, 15 lbs of Nitrogen Oxides, 6.8 lbs of Hydrogen Sulfide, 21.5 lbs of Highly Reactive Volatile Organic Compounds (HRVOCs), and 31.7 Volatile Organic Compounds (VOCs). LDEQ report states that "this incident is an area of concern with regards to LAC 33:III.905." Remedial Actions: Cut charge on 205 Coker due to Fractionator pressuring problem and removed ROSE Pitch from unit. Put ROSE unit on internal circulation. Relieved to flare.
|FLARE - North & South Ground Flares; Thermal Oxidizers #1, #2, #3; GME Thermal Oxidizer #1, #2|
FLARE - North & South Ground Flares; Thermal Oxidizers #1, #2, #3; GME Thermal Oxidizer #1, #217m
|Cause: A transformer breaker tripped causing multiple operating units to shut down, including sulfur plants. FLARE.|
Notes: RQ. Reportable Quantities were exceeded for sulfur dioxide during this incident. Detailed emissions report included. Refinery's Air Monitoring Team dispatched. "The breaker was reset and the units were quickly brought back on line." LDEQ report date is 2/18/2011.
|FLARE - North & South Ground Flares; Thermal Oxidizers #1, #2, #3; GME Thermal Oxidizer #1, #2|
FLARE - North & South Ground Flares; Thermal Oxidizers #1, #2, #3; GME Thermal Oxidizer #1, #217m
|Cause: Brief power outage caused multiple operating units to briefly shut down including sulfur plants. FLARE.|
Notes: BRQ. No reportable quantities were exceeded. Units brought back online quickly, and had to flare.
|FLARE - North Ground Flare [EQT 0282]||Cause: Unit 210 Crude Offgas Compressor Suction Drum over pressured due to excessive crude offgas from the Sats Gas Plant.|
Notes: BRQ. No reportable quantities exceeded, but detailed emissions report included. Offgas flow from the Sats Gas Plant reduced, spillback to the Crude Suction Drum closed.
|FLARE - South Flare||Cause: Crude Unit had liquid carryover into compressor suction drum, causing compressors to trip and increase the drum's pressure, opening the relief valve to the South Flare.|
Notes: BRQ. No reportable quantities were exceeded, but detailed emissions report included. Flow to compressors stopped, level in the drum pumped down; restarted and flow resumed asap.
|South Ground Flare (EQT 0284)||Cause: New Naphtha Hydrotreating Unit relief valve failed--opened intermittently at lower pressures than it was supposed to and sent stream to flare. Discovered problem thanks to citizen complaint re: the smell.
Reportable quantity for SO2 exceeded.
Duration given below is an estimate; emissions were intermittent from 1758 hrs to 2215 hrs.|
Notes: RQ. Faulty valve taken out of service & sent for repairs. RQ. Detailed release calculations attached to refinery letter.
|FLARE: south flare||Cause: COLD WEATHER. "Freeze-related issue": eocene interstage drum filled with liquid due to a frozen drain line, tripped compressors, relief valve on the crude vacuum overhead opened to flare.
Emissions table in report dark and hard to read.|
Notes: Air monitoring team dispatched, crude vacuum gas to flare closed off and re-routed, bypass valve opened but did not drop level in time, steam hose hooked up to the controller to clear line. Refinery Letter states that reportable quantities were not exceeded [BRQ]. Detailed emissions report included.
|205 Coker Unit to Unit 259 North Ground Flare||Cause: The incident occurred when the facility was switching from the online drum to the blowdown drum. During the switch, the Wet Gas Compressor surge controller attempted to open the second stage spillback valve. The valve hesitated to open, causing a spillback to trip open. This caused the frac and blowdown to pressure up and the compressor to send the product to the flare until the operations pressure returned to normal.
At the time of the written notification, the incident was still being investigated to determine the cause of the overpressure condition.|
Notes: The unit pressure levels were automatically corrected by the wet gas compressor surge control system.
|Includes U21, U43, U55, U212, and U243||Cause: On 10/21/11 the Propane Shipping Pump, 63-1537-01, was shutdown due to vibration problems which limited propane throughout the refinery. Operations made moves to cut charge rates and lined up the propane to the fuel gas system. Intermittently flared from Units 21, 43, 55, 212, and 243. No known off site impacts. Incident investigation is being conducted to determined the why the incident occurred.|
Notes: Opened 21P6431C, sweet fuel gas valve to flare to reduce pressure on fuel gas header and lower the level in 43-1202 (3:22am -4:09 am) bullet. Unit 63 shutdown propane shoppin pump, 63-1537-01, and U22 & U222 propane was routed to the bullet, 21HC6431 sweet fuel gas valve opened to the south flare from (8:21 am - 3:30pm). Fuel Gas Mix Drum 243-PC-0180B opened to flare due to Unit 205 sending excess propane to fuel gas header. Valve opened intermittently during this time from (11:15 am- 4:28pm) not opened above 10%. C3 propane from Domains 1 and 9 in refinery fuel gas causing high fuel gas pressure and 43PC5355 opened to flare three times (11:20am-11:30am), (11:53am-12:20pm), (12:45pm-1:05pm). Unit 55 Flare sweet refinery fuel gas from C3 propane in RFG Domain 1 and 9, 10/22/11 (11:28 am -3:55pm), 10/22/11 (7:42pm)- 10/23/11 (4:07am). An incident investigation will result in recommendation items designed to prevent the recurrence of this event. Values for carbon monoxide and nitrogen oxides do not match the sum of the daily reports. They are higher than the sum of the reportable values.
|Unit 259 South Ground Flare (EQT 286)||Cause: A heat exchanger in the Hydrocracker Unit (Unit 215) began to leak as the unit was starting up and achieving normal operating conditions. Some material was depressured to the flare so that maintenance on the exchanger could be performed.
An incident investigation is being conducted to determine why the incident occurred.|
Notes: The equipment was allowed to depressure to the flare until repairs could be made. At the time of the police report, all had been secured. An incident investigation will result in recommendation items designed to prevent the recurrence of this event.
|Unit 59 North Flare||Cause: The pressure relief valve on the unit 232 rich amine flash drum failed. Material in the flash drum was depressured by flaring until the relief valve would have closed. Leaking release valve and sour water stripper. Material was sent to Unit 59 North Flare (EQT# 0162 and EIQ# 83-74)|
Notes: The flash drum was allowed to depressure to the flare until the relief valve would have close and the valve could be repaired. an incident investigation will result in recommendation items designed to prevent the recurrence of this event.
FLARE: Unit 59 North Flare (EQT #0162 EIQ #81-74)
|Cause: Refinery letter states that pressure on main fractionator unexpectedly increased, and pressure control valve to the flare opened to decrease the pressure. Sulfur dioxide was released to the air. Refinery letter states that "all aspects of this incident/upset are currently under investigation." FLARE.|
Notes: BRQ. No Information Given. Refinery letter states that "all aspects of this incident/upset are currently under investigation."
Unit 59 South Flare
|Cause: A tube leaked on the Unit 15 Hot Separator Overhead Fin Fans at 17:52 hours. At 18:00, the unit was undergoing emergency shutdown procedures and the U15 dump valve was opened to the flare. The incident was a Gas Oil leak in the Unit 15 Hot separator Overhead Fin Fan Exchangers.
This leak caused a vapor release of hydrocarbons and hydrogen in addition to a small amount of hydrogen sulfide.|
Notes: PDF was too large to upload. Unit 15 was depressurized to the South Flare to safely isolate the leaking Overhead Fin Fan. Once the unit pressure was sufficiently low in the unit, the Fin Fans were isolated and the leak stopped. An incident investigation will result in recommendations to prevent recurrence. The reportable quantities for hydrogen sulfide, compressed flammable gas, and compressed flammable liquid were exceeded during this event. A report on October 9, 2013, removed greenhouse gas emissions and revised the estimate of VOC emissions.
|Unit 59 North Flare||Cause: A unit upset occurred in the Fluidized Catalytic Cracking Unit (FCCU) due to a sudden shift in feed composition. Subsequently, pressure increased in the fractionator overhead accumulator causing the pressure control valve to open to the refinery's North Flare for 11 minutes.|
Unit 59 North Flare
|Cause: The initiating incident was a pump seal fire in the Gasoline Desulfurization Unit (Unit 55). The fire was fueled by a leaking seal on the pump. Extinguishing the fire was delayed by inability to close an EIV on the suction side of the pump. This resulted in emergency shutdown of the unit. Two other events also occurred on this day including an upset in Sulfur Plant Unit 234 and a flame-out of the North Flare. Due to the fire and emergency shutdown of the Gasoline Desulfurization Unit, the Fluid Catalytic Cracking Unit cut feed, sending vent gas to the North Flare. Process vent gas was sent to the North Flare which increased the steam to the flare suddenly, snuffing the flare out.|
Notes: PDF too large to upload (109 pages) To re-light the North Flare, steam was gradually decreased and natural gas was added to the flare gas to allow the two available igniters to relight the North Flare. Parts to repair the North Flare pilot system were already on order when this incident occurred. The North Flare was taken out of service when the parts were received and repaired on October 31, 2012. Spare pilot and igniter assemblies are now in stock so that repairs can be made in a timely fashion if an incident like this is to occur again. Total amount of pollutants released was 59438.44 lbs, but 90% was claimed to be efficiently burned off, resulting in 5943.59 lbs that were actually released. The reportable quantity for Highly Reactive Volatile Organic Compounds (HRVOCs) (100 pounds) was exceeded during the 24 hour period.
|Emissions from Flare|
emissions from flare and Unit 45 Thermal Oxidizer
|Cause: Marathon experienced a partial power outage caused by a malfunctioning substation in the refinery resulted in multiple pieces of equipment in the refinery losing power.
Low pressure stripper Offgas flared in the South Flare due to partial power outage.
Enterprise incident due to a plant farther downstream that had uncharacteristically ceased operation due to an upset condition. The pressure safety valve, as designed, released discharging natural gas to atmosphere due to high pressure on the pipeline caused by the upset condition farther down the line.
Emission points involved were the Unit 59 North Flare and the Unit 45 Thermal Oxidizer.|
Notes: Marathon power was restored and the equipment that was shutdown was restarted to minimize further releases. An incident investigation will result in recommendation items designed to prevent the recurrence of this event. High sulfur dioxide from one of the thermal oxidizer stacks in Unit 45 and in addition to a small amount of Unit 15 low pressure stripper offgas was flared which contains a small amount of hydrogen sulfide which is converted to sulfur dioxide in the North Flare. Emission points involved were the Unit 59 North Flare and the Unit 45 Thermal Oxidizer. Enterprise personnel immediately began the process of taking the plant down in order to end the release event. Amount of natural gas released is above reportable quantity.
|Unit 259 North Ground Flare (EQT #282 EIQ #20A-08)||Cause: The U205 coker 1202 drum pressured up causing a corresponding pressure build up in the blow down system. The drum experienced a "refoaming event" where steam is introduced into the drum immediately following a drum swap causing the partial pressure of the unconverted material in the drum to drop. This resulted in over pressuring the fractionator. Pressure relief valves 205-P1511(V1) and 205-P1511(V2) then opened to the North Ground Flare.|
Notes: Initial report states that the charge rate to the unit was immediately reduced, but that no specific remedial actions were taken or planned at that time. Follow up report states that a TapRoot Investigation was conducted to determine the cause of the incident. This investigation found that the causal factors were: 1) the drum inlet temperature was too low for the cycle and 2) after the drum swap, the valve ramp program pinched the combined overhead valve to 40% and the throttling of this valve contributed to the overpressure of the drums. The investigation recommended: 1) Implement a low drum inlet temperature alarm on both Coke Drums, 2) Develop a drum inlet temperature controller to allow operations to fire the heater based on drum inlet temperature, and 3) Evaluate removing the combined overhead valve ramp down program after a drum swap. Recommendations 1 and 2 were completed by 11/15/2012. Recommendation 3 was not completed.
|unit 34, thermal oxidizer||Cause: An investigation is underway to determine the cause of the incident.
False reading on a flow transmitter. Following the shutdown, feed increased to Unit 34 and shutdown the oxygen skid. This resulted in high sulfur dioxide and visible emission from the U34 thermal oxidizer.|
Notes: The refinery's ambient air monitoring station data did not exceed the NAAQs for Sulfur dioxide. The refinery's Air Monitoring team was dispatched to monitor the community downwind of the incident. There were no other known off-site impacts. The Unit 234 was restarted. Maintenance steamed out the flow transmitter with the faulty reading. U34 oxygen skid was restarted. Specific remedial action unknown at this time; an incident investigation will result in recommendation items designed to prevent the recurrence of this event. They admitted to releasing 416.69 lbs more than their permitted maximum for sulfur dioxide. The total sulfur dioxide released was actually 639.64 lbs. The facility claimed that the reportable quantity for sulfur dioxide was not exceeded, however, the opacity limit from the thermal oxidizer was exceeded.
|Flange on the Pitch Exchanger 210-1317-08|
North Ground Flare
|Cause: The 210-1513-01 Vacuum Bottoms Pump inboard and outboard motor bearing housings were smoking during routine observations. The 210-1513-02 Vacuum Bottoms Pump (back-up) was already out of service for repairs. The board operator was notified and started reducing Crude charge rate. The 210-1513-01 Vacuum Bottoms pump was shut down due to the outboard motor bearing igniting. The 210 Crude Unit shutdown procedure was initiated. The 210-1801-01 Offgas Compressor tripped due to a high level in the 210-1202 Compressor Suction Drum. Both pumps were already on in automatic. The outsider operator opened the bypass around the flow controller to the Product Receiver. Crude overhead gas was flared in the North Ground Flare. About 5 gallons of crude oil from a flange on the Refinery's Oily Water Sewer and processed in the WWTP.|
Notes: The boardman cut charge rates to Crude Unit 10 and shut down Crude Unit 210. Both Compressor Suction Drum pumps were turned on, and the bypass around the flow controller was opened. The operator increased the suction drum pressure to assist the pumps in pressuring out the level to the startup compressor. The incident investigation will result in recommendation items designed to prevent the recurrence of this event. Initial report states material did go offsite. Verbal report and Hazardous Materials Incident Reporting Form state that H2S was released (and incorrectly reporting that the reportable quantity for it is 500 lbs), while the refinery statement letter reports only SO2.
|Unit 20 Thermal Oxidizer, Unit 34 Thermal Oxidizer, Unit 45 Thermal Oxidizer, Unit 220 Thermal Oxidizer, Unit 234 Thermal Oxidizer, and all process heaters that combust refinery fuel gas.||Cause: Chain of Events: While placing amine filters in service, an upset occurred in the Unit 247 Amine Regeneration Unit Overhead Receiver. A high liquid level in the Receiver caused liquid to be sent to the Sulfur Plants. The Unit 220 and 234 Sulfur Plants shut down due to high knockout drum levels. This caused an elevated flow to the remaining operational sulfur plants. The Unit 34 Sulfur Plant then shutdown due to low boiler feed water level in the Reaction Furnace. Unit 247's lean amine became saturated as a result of the high acid gas header pressure, resulting in less than adequate hydrogen sulfide absorption in RFG producing units, causing both Refinery Fuel Gas Mix Drums to experience high levels of hydrogen sulfide. This fuel gas was then combusted in all the refinery's heaters that were operating on refinery fuel gas.
Summary: An upset in the Unit 247 Amine Regeneration Unit caused an opacity exceedance and sulfur dioxide reportable quantity exceedance in the Sulfur Plants and at all the process heaters, which combust refinery fuel gas.
MPC originally reported that the upset began in the Coker Unit, but, after further investigation, stated that the Coker Unit was not involved in the incident.|
Notes: Process unit charge rates were reduced in accordance with the refinery's sulfur shedding plan. Sulfur plants were re-started as soon as possible in order to convert more hydrogen sulfide to sulfur. The refinery dispatched 3 Air Monitoring Teams, and no pollutants were detected at the fenceline. The Air Monitoring Team data is attached to the report. Mobile SO2 meter was post calibration expiration. (AreaRAE #240) Corrective actions given in follow-up report: Review and reinforce procedure use with 552 Board Operator, Issues Lessons Learned to emphasize the requirement and importance of using procedures, Review and reinforce procedure use with 532 Operator, Investigate a means to maintain LP BFW header supply while spare LP BFW is out-of-service, Investigate upgrading U220/U234 Amine Acid Gas KO Drum Pumps from 25 gpm max to 50 gpm max, Train 001 shift supervisors on the updated refinery sulfur shedding procedure and importance of following the procedure to emliminate a large sulfur dioxide emissions incident, Update Unite 232/247 Carbon After Filter Change-out Procedure to utilize FC0051 to help ensure that a surge of flow cannot be routed to Regenerator during the filter start-up, Update DCS graphics to clean-up the FC0051 split-range control and PC0021 selector control schematic to help improve operator understanding, Provide face-to-face training on the updated procedure and schematics for each Board Operator, and Update refinery sulfur shedding procedure such that unit charge rates are reduced quickly enough to minimize sulfur dioxide emissions during sulfur unit shutdowns.
|Unit 59 North Flare||Cause: The incident that occurred was a unit shutdown and associated flaring event. The wet gas compressor in the Fluidized Catalytic Cracking Unit tripped offline followed by an entire unit shutdown. The shutdown caused hydrocarbons to be routed to the north flare.|
Notes: RQs exceeded for SO2 and HRVOCs. Also, the opacity standard was exceeded for 8 minutes. Incident only lasted 26 minutes, but the depressuring of the unit continued and flaring lasted approximately 425 minutes. Remediations included cleaning the wet gas compressor motor aux contact and retest to verify appropriate resistance, and also revised compressor control system programming to include motor current to improve reliability of failed-to-start interlock logic.
|Unit 59 South Flare (EQT0160, EIQ69-74)||Cause: During an upset of the U15 High Pressure Stripper, liquid and vapor were sent to the 19-1211 Fuel Gas Absorber KO Drum. A control valve and a bypass were opened on the bottom of the drum, sending liquid to the flare in order to maintain level in the drum.|
Notes: In U15, HP Stripping Steam was cut and charge was reduced to bring the upset under control.
|Unit 59 North Flare||Cause: A root cause analysis is being conducted to determine why this incident occurred.
The Louisiana Refining Division's Investigative Summary Report states that the initiating event was the troubleshooting common alarm on the Bently Nevada radial vibration proximitor card to include a module self-test for diagnostic information.|
Notes: Operations restarted the Wet Gas Compressor. The root cause analysis will result in recommendation items designed to prevent the recurrence of this event. The refinery stated that lessons learned included: On a Bently Nevada 3500 system, a module self-test or replacement will cause the output signal to go to 0ma. If the output signal is wired to a Triconex system, it will report the transmitter as being an unreliable signal (bad transmitter of bad pv). VOC chemical breakdown is provided. Only the RQ for SO2 was exceeded during this release.
|Unit 259 North Ground Flare (EQT #0282)||Cause: During the Unit 215 Startup on February 4, 2012, the Recycle Gas Scrubber foamed shortly after the lean amine circulation started causing a high level in the Recycle Gas KO Drum, shutting down the Recycle Compressor. Shortly after the Recycle Compressor was re-started, a high temperature wave went through the Train 2 Guard reactor and activated the Train 2 Guard Bed No. 3 bottom catalyst layer rate of change trip initiating a high rate de-pressure via ESD-1. There were no known off-site impacts.
On February 4, 2012, 2274 pounds of SO2 were released. On February 5, 2012, 6630 pounds of SO2 were released.|
Notes: Calculations for SO2 emissions provided in attachments 1A and 1B. LABB was unable to find attachments. The compressor was re-started initially. The Emergency Shutdown (ESD) system activated as designed. An incident investigation was conducted to determine the cause or causes of the incident. Per this investigation, the root causes were identified as 1. procedures wrong- situation not covered and 2. equipment difficulty- design specs need improvement. The recommendations (actions) from the investigation were 1. determine correct Unit 232 operation while Unit 215 is shutdown to ensure that sufficient anti-foam is in the system- completed on 3/19/12; 2. add a step to the unit 215 startup procedure to ensure that Unit 232 is injecting high rates of antifoam at least one hour prior to taking amine- completed 10/1/12; and 3. adjust the ESD logic to increase the temperature at which the rate of change alarms become active - completed 9/19/12. Two incident investigations were conducted to determine the cause or causes of the incident. The first investigation focused on the cause of the electrical failure in Unit 215 which was the origin of the problems in Unit 210. Per this first investigations, the root cause was identified as Equipment difficulty- problem not anticipated. This first investigation had four recommendations (actions) which were 1) have IR windows reinstalled on the 215-1501-A charge pump motor connection box during the next available shutdown- due 8/15/14; 2) Logically "AND" a "50N2T" element to the "RUNNING" element and add it to the trip logic for all 15KV motors that are protected by SEL-710 relays -due 2/29/16; 3) Convert all 15KV connection boxes in service and warehouse stock to include rupture panels - due 8/15/14; and 4) modify standard practice SP-60-27 and SP-60-29 for all induction and synchronous motors to include the requirement for a rupture panel to be installed on the motor connection box- 8/2/12. The second investigation focused on the shutdown of the U210 off-gas compressor, source of the flaring in this incident. Per this investigation, the root causes were identified as 1) Training- understanding needs improvement, 2) Human engineering- human machine interface, 3) communication- no communication or not timely. And 4) Procedures- followed incorrectly. This second investigation had six recommendations (actions ) which were 1) review the need for quickly restarting the compressor with domain 9 operations personnel- completed 3/28/12; 2) Add to board operator training outline a section to review critical actions following the loss of multiple pieces of equipment- completed 6/29/12; 3) raise the priority of the alarm for the suction drum vent valve open to flare from high to urgent- completed 3/29/12; 4) lock the primary alarm summary display on the DCS to sort alarms by priority- completed 3/29/12; 5) review the incident and the need for clear and concise communication during upset conditions with Domain 9 operations personnel- completed 3/28/12; and 6) revise the Unit 210 Off-Gas compressor startup procedure to specify that the board operator loads the compressor and verifies good operation- completed 5/1/12.
|Unit 59 South Flare, Unit 45 Thermal Oxidizer, Unit 220 Thermal Oxidizer, Unit 234 Thermal Oxidizer, and Unit 33 Sour Water Tank||Cause: Chain of Events:
1/14/12: Hydrocarbon carryover from the Unit 19 Sour Water Stripper caused Unit 220 (sulfur unit) and Unit 45 Thermal Oxidizer to trip. As a result, a sulfur dioxide plume was released from the Unit 45 Thermal Oxidizer. During the release, hydrocarbons from the ammonia acid gas header were steamed out to the flare. Units were then shut down to limit environmental impact.
1/15/12: A similar incident took place approximately four hours after Unit 220 startup. During this incident, the flare valve on the fuel gas absorber knockout drum opened to flare to relieve pressure on the drum. Hydrocarbon from the carryover was also sent to the sour water storage tank, which resulted in the tank venting to the atmosphere.
1/16/12: The flare valve from the fuel gas absorber knockout drum was closed at approximately 9:30, and the incident was then determined to be secure.
The entire incident is under investigation.
Follow up report issued 2/26/2013 summarizes results of internal Marathon investigation.|
Notes: During the initial upset (1/14/12), Cargill was notified of the plume. All work with the Marathon refinery was put on hold, and the plant's Air Monitoring Team (AMT) was dispatched. The data that they collected is attached to the report. The contents of the Unit 19 Sour Water Storage Tank and ammonia acid gas header were then purged to eliminate existing hydrocarbons. Similar actions were taken to mitigate emissions from the second incident (1/15/12). Units were shut down, the AMT was activated, and fire water was introduced to limit emissions from the sour water tank. This incident was determined to be secured (1/16/12) when the flare valve from the fuel gas absorber knockout drum was closed to the South Flare. An incident investigation was conducted to determine the cause or causes of the incident. Per this investigation, the root cause was identified as Equipment Difficulty-Problem Not Anticipated. The recommendation from this investigation was to review disposition of Fuel Gas Absorber knock-out drum liquid. Report states this action was completed 6/27/12. Only states that SO2 emissions were above reportable quantities.
|Unit 59 South Flare, Unit 45 Thermal Oxidizer, Unit 220 Thermal Oxidizer, Unit 234 Thermal Oxidizer, and Unit 33 Sour Water Tank||Cause: The incident began on January 14, 2012 at 02:25 hours and ended at approximately 09:35 hours on January 16, 2012. The incident lasted roughly 55 hours.
On January 14, 2012, hydrocarbon carryover from the Unit 19 Sour Water Stripper caused Unit 220 (sulfur unit) and Unit 45 Thermal Oxidizer to trip. As a result, a sulfur dioxide (SO2) plume was released from the Unit 45 Thermal Oxidizer. During the release, hydrocarbons from the ammonia acid gas header were steamed out to flare. Units were then shutdown to limit environmental impact.
Approximately four hours after Unit 220 startup the following day, a similar incident took place. Hydrocarbon carryover from the unit 19 sour water stripper caused Unit 220, 234, and Unit 45 Thermal Oxidizers to trip. The thermal oxidizer released a plume of SO2 to the atmosphere. During this incident, the flare valve on the fuel gas absorber knockout drum opened to flare to relieve pressure on the drum. Hydrocarbon from the carryover was also sent to the sour water storage tank which resulted in the tank venting to the atmosphere. The flare valve from the fuel gas absorber knockout drum was closed at approximately 09:30 on January 16; the incident was then determined to be secure.|
Notes: During the initial upset, Cargill was notified of the plume. All work within the Marathon refinery was put on hold and the plant's Air Monitoring Team (AMT) was dispatched. The data collected is included in attachment 2. The contents of the Unit 19 Sour Water Storage Tank and ammonia (NH3) acid gas header were then purged to eliminate existing hydrocarbons. Similar actions were taken to mitigate emissions from the second incident. Units were shutdown, the AMT was activated, and fire water was introduced to limit emissions from the sour water tank. The incident was determined to be secure when the flare valve from the fuel gas absorber knockout drum was closed to the South Flare. The refinery report mentions that sulfur dioxide was released above RQ, but no calculations were provided. It states calculations are located in the attachment, but LABB could not locate said attachment. The RQ for SO2 is 500 pounds.
|Heater on Unit 43 Fuel Gas Mix Drum||Cause: Unit 19 received a slug of rich amine, during the unit 15 start-up, causing the amine regenerator to slump and was unable to be removed from the stream. The amine, still rich with Hydrogen Sulfide, was then sent to the Fuel Gas Absorber tower and was unable to remove Hyrdogen Sulfide from the fuel gas. The fuel gas was then sent to the Fuel Gas Mixed Drum, which was supplying fuel gas to 22 sources. As a result, several heaters and boilers experienced an increase in Sulfur Dioxide above the maximum allowable permitted lbs/hr rate.
A TAPROOT investigation concluded that the accident was caused by Human Performance (the 519 operator thought the board operator meant to close the spillback instead of the lean internal circulation) and Equipment Difficulty (steam trap system malfunctioned due to new Fuel Gas Project tie in).
LDEQ conducted an Air Quality Compliance Incident Investigation Report in response to this accident.|
Notes: See Page 3 for very detailed list of point sources with names, unit numbers etc. The 60-day report recommends that the refinery revise the Unit 19 Start up procedure with more detailing events on when to use the internal lean circulation line while starting up Unit 15 with the appropriate line terminology, label lines accordingly, and retrain operators with the revisions. This report recommends additionally that the refinery evaluate the design of the existing steam tracing for the analyzer, and recommend proper mitigation. No report does not provide information of the the refinery's implementation of these recommendations. LDEQ Enforcement Division found that MPC failed to operate the lean amine circulation line in the closed position for the proper working order of the Lean Regenerator to control emissions by the facility. Facility will revise Unit start up procedures with operators.
|North Ground Flare|
North Ground Flare, Heaters on Unit 243, Unit 43, and Unit 59
|Cause: According to the the 60-day report, the Triconix safety control system inadvertently tripped the Unit 247 Amine Unit Lean Amine Pumps. The pump shutdown caused lean amine to stop circulating to the Fuel Gas Treaters which caused high H2S-laden fuel gas to be sent to the Unit 243 Fuel Gas Drum. In addition, untreated fuel gas was sent to the Unit 43 Fuel Gas Mix Drum. The Fuel Fuel Gas Mix Drums were supplying fuel ga to 26 different process heaters and boilers with the refinery during the incident. As a result, each heater and boiler experienced an increase in SO2 emissions above the maximum allowable permitted lbs/hr rate. In addition, the Unit 247 Flash Drum overfilled into the vapor line to the Unit 210 Compressor Suction Drum, thus causing the compressor to temporarily shut down which resulted in venting to the North Ground Flare.|
Notes: The refinery Air Monitoring Team was dispatched inside and outside the refinery fenceline. All SO2 and H2S readings were non-detect except for one 4ppm SO2 reading on Marathon Avenue in the refinery. No elevated ambient air monitoring readings from MPCs four ambient air monitoring stations were detected during the event. Operations re-started the Unit 247 lean amine pumps and re-established amine circulation to the Amine Treaters. This recirculation brought the H2S amounts in the fuel down to acceptable levels. The reportable quantity for sulfur dioxide was exceeded during the event. In addition, the permitted SO2 and the NSPS Subpart J/Ja SO2 limit for the emission sources was exceeded for multiple hours. The opacity limits for the above listed heaters and boilers were exceeded. Report was unable to be uploaded. Recommendations made for the Root cause were:1) Human Performance- Revise the Unit 19 Start up procedure with more detailing events on when to the internal lean circulation line while starting up Unit 25 with the appropriate line terminology, label lines accordingly, and retrain operators with the revision. 2) Equitment Difficulty- Evaluate the design of the existing steam tracing for the analyzer, and recommend proper mitigation.
|No LDEQ Reported|
|Unit 250 North Ground Flare||Cause: On July 24, 2013, the Unit 210 Crude Overhead Compressor shut down at 16:11 hours and was restarted at 16:26 hours. A second shutdown occurred at 16:48 hours and was restarted at 17:02 hours. A third shutdown occurred at 17:25 hours and was re-started at 17:56 hours. The duration of Unit 210 venting to the North Ground Flare was 60 minutes.
Approximately 613 pounds of sulfur dioxide were released (over the reportable quantity of 500 pounds).|
Notes: Liquid was drained from the Unit 210 Compressor Suction Drum. The Unit 210 Crude Overhead Compressor was re-started. A very similar event occurred on March 25, 2013 with emissions from the same point source. This report retrieved from EDMS was labeled with the LDEQ number corresponding to the March 25, 2013 incident (LDEQ # 147603). The March 25th event also involved multiple shutdowns of the Unit 210 Crude Overhead Compressor, and the report labeled that event as preventable. It is interesting to note that a similar event labeled preventable occurred less than four months later.
|Unit 259 North Ground Flare||Cause: On July 24, the Unit 222 Debutanizer Accumulator level reached 100%. This condition caused the pressure controller to open sending liquid overhead to the Unit 210 Compressor Suction Drum. The high level in the Compressor Suction Drum caused a shutdown of the Crude Overhead Compressors and a release to the North Ground Flare.|
Notes: Liquid was drained from the Unit 210 Compressor Suction Drum. The unit 210 Crude Overhead Compressor was restarted. To prevent recurrence of a liquid overfill from putting liquid into the Low Pressure Recovery Header (LPRH) and tripping the U210 compressors, it is recommended to: institute a high level override on 222PC0316-02 that will close 222PC0316-02 in the event of a high level in the Debutanizer Accumulator; institute a high level trip on U214 Feed Surge Drum pressure controller, U214 LP Stripper Overhead Receiver, U215 Coker Feed Surge Drum, U215 Feed Surge Drum, U215 Fractionator Overhead Receiver, and U215 Naphtha Splitter Overhead Receiver that will close the vent to the LPRH in the event of a high level in the respective vessel. To prevent recurrence of tripping the compressors due to overwhelming the Suction Drum pumps, it is recommended to: evaluate all sources to the LPRH that do not currently have a control valve, and evaluate all sources to the Eocene header to determine if additional safeguard are required to prevent liquid carryover. Also, it is recommended to determine what the normal operating pressure and low alarm set point should be to insure the Interstage KO Drum Pumps can successfully pump any material that condenses in the KO drum, update the alarm database with information regarding the importance of KO drum pressure on operation of the KO Drum pumps, and evaluate the performance of the U210 Interstage KO Drum Pressure during INC49711 to determine if tuning parameters can be changed or controls modified to allow the pressure set point on the drum to be reached quickly after startup of the U210 compressors. An additional followup on 10/23/13 corrected the initial followup report's emissions data regarding greenhouse gas releases.
|No LDEQ Reported|
|Crude Unit Overhead Accumulator||Cause: On July 21, 2013, an overpressure condition in the Crude Unit Overhead Accumulator due to the shutdown of the Sats Gas Unit.|
Notes: An initial report for this incident, which included details on what happened and what pollutants were emitted in what quantities, was submitted to LDEQ on July 26, 2013. This follow-up report corrects emissions data submitted by Marathon which originally included greenhouse gas emissions in the incident calculations.
|Unit 259 North Ground Flare||Cause: On July 15, 2013, due to a crude oil switch, a high level occurred in the Unit 222 Sats Gas Plant (SGP) Compressor Suction Drum which caused the Sats Gas PLant Compressor to temporarily shutdown. This resulted in some flaring of the overhead gas to the North Ground Flare for about 55 minutes.
The first incident began at 09:05 hours on July 15, 2013, and was secured by 10:00 hours. The second incident began at 19:32 hours on July 15, 2013, and was secured by 19:33 hours.|
Notes: For Incident 1, the level in the Sats Gas Plant Compressor Suction Drum was lowered and the Sats Gas Plant Compressor was re-started. For Incident 2, operating personnel made operating changes to the unit to bring it out of upset conditions. These incidents will be investigated and an action plan to prevent recurrence will be generated. Follow up report submitted 10/23/13 states that original report included Greenhouse Gas emissions, however these emissions are not required to be evaluated for reportable quantity because they are not permitted pollutants. The report updates the calculations without greenhouse gases included.
|Unit 259 North Ground Flare||Cause: ON July 15, 2013, an upset in Crude Unit 210 caused the Crude Compressor Suction Drum to vent to the North Ground Flare for approximately one minute.
The first incident was due to a crude oil switch causing the Unit 22 Sats Gas Plant Compressor to shutdown on high level. The second incident was due to an upset in the Unit 210 Crude Unit that cause the Unit 210 Crude Compressor Suction Drum to vent to the North Ground Flare.|
Notes: Operating personnel made operating changes to the unit to bring it out of upset conditions. October 23, 2013 additional follow-up report corrects emissions data submitted by MPC. MPC erroneously included greenhouse gas (GHG) emissions in the incident calculation. GHGs are not permitted pollutant and are not required to be evaluated for reportable quantities.
|all heaters and boilers that are supplied fuel gas from the Unit 43 Fuel Gas Mix Drum||Cause: The Unit 47 Amine Unit tripped twice on June 24. The trips caused an increase in hydrogen sulfide going to the Unit 43 Fuel Gas Mix Drum which would have normally been removed by the Amine Unit. The Fuel Gas Mix Drum supplies fuel gas to 28 different process heaters within the refinery. As a result, each heater experienced an increase in sulfur dioxide emissions above the maximum allowable permitted lbs/hr rate.
The two ambient air monitoring stations located downwind of the incident did not detect a significant increase in sulfur dioxide emissions.|
Notes: Operations re-established amine system levels, restarted the Unit 47 lean amine pump and re-established amine circulation to the Amine Treaters. The U-5 LPG Treater amine circulation rate was restricted at a lower flow rate due to foaming/emulsion as evidenced prior to shutdown. The Unit 47 Amine Unit was brought back on-line removing hydrogen sulfide from the fuel gas. Recommendations: - Tech Service to be present while inspecting the Sponge Oil Absorber during the October 2013 Shutdown. - Develop temporary operating guidelines to address tower operation at reduced gas rates. - Issue a lesson learned on this incident to D5, D7, & D8 operators & supervisors. - Add a low level override controller on the U-19/47/221/232/247 amine strippers to reduce the amine flow to their respective treaters. - Add a low level override controller on the U-32 mine stripper flow to the respective treaters (4). - Modify the low level override controller on the U-21 amine stripper flow to the respective treaters (3) to include #3 TGTU.
|Unit 259 North Ground Flare||Cause: On April 20, 2013 the Unit 210 Crude Unit experienced an upset due to a change in the incoming crude state. The flaring in U210 and U222 associated with the upset started at 7:12 AM on April 20, 2013 and was complete at 8:35 AM on April 20, 2013. The duration of Unit 210 and 222 venting to the North Ground Flare was 83 minutes. Approximately 75 pounds of sulfur dioxide were released.
The Unit 210 Crude Unit experienced an upset due to a change in the incoming crude state. The incoming crude had a greater quantity of light components as well as some water. The upset resulted in high liquid levels in vessels upstream of the crude off-gas compressors and the sals gas compressor. In order to minimize the amount of liquid sent to the compressors, which could cause a shutdown of the compressor, a portion of the liquid generated in the upset was routed to the North Ground Flare knock out drum. This action reduced the severity of the incident.|
Notes: The crude tank line up was modified to remove the tank thought to be the cause of the water and light ends going to the Crude Unit. In addition, the crude charge rate was reduced to help manage the unit upset. The routing of liquids to the flare knock out drum was an attempt to minimize the results of the upset and prevent equipment shutdowns which would ahve resulted in a much more significant release. An additional followup on 10/23/13 corrected the initial followup report's emissions data regarding greenhouse gas releases.
|Unit 259 North Ground Flare||Cause: The two root causes identified were the benzene stripper lower level controller malfunctioned and the operator did not have sufficient response time.
On March 25, 2013 the Unit 210 Crude Overhead Compressor shut down at 18:03 hours and was restarted at 18:26 hours. A second shutdown occurred at 19:23 hours and was re-started at 19:41 hours. The duration of Unit 210 venting to the North Ground Flare was 40 minutes. Approximately 3,385 pounds of sulfur dioxide were released (above the reportable quantity of 500 pounds).
On March 25, 2013 at 17:45 hours, issues developed in the Unit 210 Desalter vessels. As a result of the event, liquid was carried over from the Desalters to downstream Unit 210 vessels. Eventually, liquid filled the Unit 210 Overhead Compressor Feed Knockout drum which shut down the Overhead Compressor. The ambient air monitoring stations located by the ground flares did not detect a significant increase in sulfur dioxide emissions.|
Notes: Liquid was drained from the Unit 210 Crude Overhead Compressor Feed Knockout Drum. The Unit 210 Crude Overhead Compressor was re-started. While sulfur dioxide was the only chemical released above reportable quantity, NOx, monoxide, VOCs, PM10, PM2.5,HRVOCs, and hydrogen sulfide were released over the permit limit. An accident investigation was conducted to determine the cause(s) of the incident. The two root causes identified were 1. Equipment difficulty, design, problem not anticipated (Benzene stripper lower level controller malfunctioned); and 2. human engineering, non-fault tolerant system, errors not recoverable (operator did not have sufficient response time). The following recommendations will be implemented: 1. redesign or upgrade the benzene stripper level indicator 210L10197 to provide backup level indication for 210LC0187 due 12/20/13; 2. add soft stops to 210L1097 to limit flow from the 1st stage Desalter to the Benzene Stripper- complete; and 3. evaluate the hydraulics of the Benzene Stripper bottoms circuit and consider developing a project to eliminate constraints in the system- due 12/20/13.
|Unit 259 South Ground Flare and Unit 259 North Ground Flare||Cause: The Unit 214 Kerosene Hydrotreater experienced an emergency shutdown at 16:18 hours on February 21, 2013. The process unit vented to the South Ground Flare for 94 minutes. The Unit 210 Crude Overhead Compressor shutdown at 16:39 hours on February 21, 2013 was re-started at 16:58 hours on February 21, 2013. The duration of Unit 210 venting to the North Ground Flare was 19 minutes.
On February 21, 2013, at 16:18 hours, a power failure caused the Unit 214 Kerosene Hydrotreater to experience an emergency shutdown. As a result of the event, liquid was carried over from Unit 214 to the Unit 210 Crude Overhead Compressor system. The liquid filled the Unit 210 Overhead Compressor Feed Knockout drum which shut down the Overhead Compressor. The ambient air monitoring stations located by the ground flares did not detect a significant increase in sulfur dioxide emissions.
The main parts of this accident were the emergency shutdown of the 214 Kerosene Hydrotreater and flaring from the Unit 210 Crude Overhead Compressor.
The causal factor for the Unit 214 Power Failure and subsequent emergency shutdown was determined to be Equipment Difficulty/Tolerable Failure. The Causal factor for the Unit 210 flaring event was determined to be Human Performance Difficulty/Management System/SPAC Not Used/Enforcement Needs Improvement.|
Notes: Power was restored to the Unit 214 Kerosene Hydrotreater and the unit was re-started. Liquid was drained from the Unit 210 Crude Overhead Compressor Feed Knockout Drum. The Unit 210 Crude Overhead Compressor was re-started. An incident investigation will result in recommendation items designed to prevent the recurrence of this event. In the 60 day follow up report dated 4/22/13, the following remedial actions were listed in response to the release: Unit 214 portion of the upset: 1) Maintenance corrective actions immediately following release. Electricians and instrument Techs responded to the Satellite building. Power panel 214-PP-B01 main breaker and substation 214-MCC-B01 were reset establishing power to the first power supply. 214-HVAC-B008 was repaired and brought back online. 2) Operations corrective actions after the release. Unit 214 board operator started procedures for shutting down unit. Unit 214 valves 214FC0007 (Heavy Coker Naptha Feed Valve) and 214FC0006 (Kerosene from tankage valve) were closed 15 minutes after the start of the release. Operations awaited Maintenance's confimation that the unit was ready to restart. Unit 210 portion of the upset: 1) Unit 210 operators followed the event reponse matrix to verify the compressor suction drum (210-1202) level, the compressor suction drum valve position, and whether or not the suction drum pumps were running. Operations than began working to get the level down in the suction drum in preparation for restarting the OFFGAS compressors. For the Unit 214 portion of the incident the following recommendations were made: 1) Update the Marathon Standard Practice to require a cicuit breaker cooridination study for all 480V power panel installations for future projects - due 12/31/13; and 2) Evaluate the cicuit breaker coordination for all existing 480V power panels throughout the refinery and determine necessary solutions to achieve coordination where required - due 8/30/14 3) For the Unit 210 portion of the incident the following recommendation was made: Review and Reinforce the Emergency Shutdown Procedures for Unit 214 with the Board Operators - complete. An additional followup on 10/23/13 corrected the initial followup report's emissions data regarding greenhouse gas releases.
|Heaters on the Unit 243 Fuel Gas Mix Drum, Unit 234 Thermal Oxidizer #5, Unit 59 North Flare|
Unit 59 North Flare
|Cause: On February 7, 2013, around 2:15am heavy rains caused 215-1202 Hot HP Separator to swing 8 degrees high and 215-1204 Hot LP Flash Drum causing liquid carry over to the Sour Fuel Gas header. Hydrocarbons hit Unit 243 Fuel Gas Treaters and carried through to Unit 247 Amine Regenerator. This caused high SO2 on sulfur units (U34, U220, U234) thermal oxidizer stacks and high H2S in the 243 Fuel Gas Mix Drum. In order to minimize any further upsets in the refinery, the hydrocarbons were routed to the North Stick Flare. As a result, Opacity from the Units 205, 210, 212, 214, and 215 heater stacks and the North Stick Flare were observed.
Emission points involved were Unit 59 North Flare, Coker Charge Heater, Crude Heater, Naptha Hydrotreater Stripper Reboiler Heater, Platformer Heater, KHT Reactor Charge Heater, KHT STripper Reboiler Heater, HCU Train 1 Reactor Heater, HCI Train 2 Reactor Heater, HCU Fractionator Heater, Boiler #1, Thermal Oxidizer #5.
A Root Cause Investigation determined the causes of the accident to be 1) Human Performance and 2) Equipment difficulty. Details about causal factor investigation are found in attached PDF.|
Notes: Refinery wide, unit charge rates were reduced and hydrotreaters were placed on internal circulation where possible to reduce production of sour gas and sulfur plant feed. The amine that was contaminated with hydrocarbon was stripped to ensure hydrocarbon did not reach the sulfur plants and caused further emissions and/or unit trips. The Unit 215 Hydrocracker level instrumentations heat tracing and insulation was inspected to ensure proper operation. The Unit 247 Amine System Carbon Filter was also placed on-line after the carbon was replaced to remove any remaining trace hydrocarbon from the system. An additional followup on 10/23/13 corrected the initial followup report's emissions data regarding greenhouse gas releases.
|No LDEQ Reported|
|North Flare||Cause: The Unit 215 Hydrocracker Hot High Pressure Separator level control failed causing a liquid carryover to the Unit 243 Sour Fuel Gas System. The liquid hydrocarbon entered the Unit 247 amine system through the sour fuel gas treaters. Once the hydrocarbon was in the amine system, the capability to regenerate the amine was compromised, resulting in high H2S in the sweet fuel system. While working to recover regeneration, hydrocarbon was carried into the Unit 220 and Unit 234 Sulfur Recovery Units (SRU) resulting in activation of their associated ESD system. After several unsuccessful attempts to restart the SRUs, the unit 247 Amine Regenerator Tower overhead product was routed to flare to remove the hydrocarbon from the amine. Once the hydrocarbon was removed, the system returned to normal operation. The resulting emissions from this event were 57,312.75 lbs/SO2 and 611 lbs/H2S.|
Notes: 1. Process unit charge rates were reduced in accordance with the refinery's sulfur shedding plan. 2. The amine that was contaminated was stripped to ensure hydrocarbon did not reach the sulfur plants and cause further emissions and/or unnecessary unit trips. 3. Maintenance was contacted to address the failed level instrumentation in Unit 215.
|Sulfur Recovery Unit flange||Cause: On February 7, 2013, at 10:17 hours, the LDEQ Official was contacted via the Louisiana State Police. The incident was a flange fire that began at 9:51 hours on February 7, 2013, and was secured by 10:00 hours (9 minutes). The intial reports approximates that 6 pounds of total volatile organic compounds (VOCs) were released during the flange fire. A followup on October 23, 2013, revised the VOC estimate to 0.58 pounds.
The Unit was placed on internal circulation due to the Sulfur units shutting down. The outlet flange on 56-2501 Reactor outlet developed a small leak and caught on fire and burned for approximately 9 minutes.|
Notes: The flange fire was extinguished with a water hose reel station and a steam hose was placed under the insulation blanket. An incident investigation was conducted to determine the causes or causes of the incident. Per the investigation, the root cause was identified as Management System - Communication of SPAC needs improvement. 1. Evaluate the U 56 Internal Circulation Procedure to determine if any modifications can be made to mitigate or minimize the unit temperature/ pressure swings experienced. This recommendation is to be completed by May 16, 2013. 2. Investigate modifying the insulation core spec (SP-80-01) to state that all flanges are to be uninsulated. This recommendation is to be completed by July 17, 2013. 3. Coordinate the effort to verify the flanges identified which operate at temperatures above 400 degrees Fahrenheit have had their insulation removed. This recommendation is to be completed by May 31, 2013. Material did go offsite as a result of this fire. A final follow up submitted on October 23, 2013 describes greenhouse gas emissions in the original follow-up as erroneous and updates the emission estimates.
|Unit 59 South Flare||Cause: During the crude unit shutdown condensate was routed to the south stick flare, caused a release of sulfur dioxide. Release was initially thought to be over facility's permit limit, update states that no permit limits were exceeded.|
Notes: No remedial actions taken
Wet Gas Compressor
|Cause: The wet gas compressor tripped due to a motor issue, which caused the overhead of the Fractionator to pressure up. The high pressure reached a safety limit and the unit shutdown. During the time that motor was undergoing repairs, fuel gas was routed into the unit to prevent excess oxygen from getting into the unit regenerator, fractionator and overhead accumulator which resulted in flaring. The unit was then started up in accordance with a written procedures. An incident investigation was conducted and identified Equipment Difficulty-Equipment/Parts Defective-Manufacturing as the Root Cause. Investigation states that the trip was initiated by the motor differential circuit detecting a differential of currency within the motor. The motor relay was initially expected to be the issue.|
Notes: The SIS system reacted as designed to shutdown the Fluid Catalytic Cracking Unit (FCCU) due to the high pressure in the fractionator. An incident investigation was conducted and included the following recommendations: 1) Send relay to manufacturer for analysis (Complete), 2) Review findings from the manufacturer (Complete), 3) Test the differential circuit at the next available opportunity (Deadline-10/31/16)
|Unit 25 FCCU wet gas compressor shutdown||Cause: The wet gas compressor (WGC) suction flow and discharge pressure dropped suddenly, causing the WGC spillback valve to open 100%. The fractionator overhead pressure increased when the WGC spillback opened up. The high fractionator pressure SIS trip point was reached (36 psi), which tripped the unit. Fuel gas was routed to the fractionator overhead accumulator, which was being vented to the flare to keep pressure on the reactor to prevent O2 from the regen from backing into the reactor. No offsite impacts were observed by the air monitoring team. The reportable quantities for Sulfur Dioxide, HRVOCs and VOCs were exceeded.
Update: cooling coil in Alkyl Unit Vent Gas Absorber (27-1107) failed.|
Notes: The SIS system reacted as designed to shutdown the FCCU due to the opening of the compressor spillback valve. An incident investigation will result in recommendation items designed to prevent recurrence of this event. Update: The root causes were identified as 1) cooling coil in Alkyl Unit Vent Gas Absorber (27-1107) failed. Cause of failure is unknown. Root Cause #1: Cannot be determined until the Alkyl Unit Shutdown. Recommendation: Inspect the cooling coil in the Alkyl Unit Vent Gas Absorber (27-1107) and determine cause of failure. Based on the cause of failure, recommendations will be generated to prevent recurrence. [Complete by December 15, 2016] 2) Quaterly PMs on cooling coil in Alkyl Vent Gas Absorber failed to identify the coil was leaking. Root Cause #1: No Procedure. Recommendations: Create Operations procedure for performing the quarterly leak testing on the cooling coil in the alkyl Vent Gas Absorber. Include a step that requires operators to verify proper documentation of test result in PM work order closure. [Complete by November 18, 2014]. Root Cause #2 Preventive/Predictive Maintenance Needs Improvement. Indetify flouride sample locations for discovering a leak in Alkyl Vent Gas Absorber cooling coil [Complete by November 18, 2014].
|FCCU wet gas compressor first stage||Cause: A loose wire in a satellite building caused the Fluid Catalytic Cracking Unit (FCCU) wet gas compressor first stage spillback to open, which led to high fractionator pressure. The safety instrumented system (SIS) tripped the FCC unit on high fractionator pressure. During the FCC unit startup, the debutanizer pressured up and had to be vented to flare due to lack of heat in the upstream stripper reboiler (heating medium is BPA from the fractionator) which sent ethane to the debutanizer.
The flaring event due to the FCCU Shutdown began on June 7, 2014 at 14:37 hours and stopped on June 7, 2014 at 15.48 hours for a duration of 70 minutes. The flare event due to the FCCU startup began on June 7, 2014 at 18:21 hours and stopped on June 7, 2014 at 20:18 hours for a duration of 117 minutes. The total duration of the flaring was 187 minutes.|
Notes: The SIS system reacted as designed to shutdown the FCCU due to the opening of the compressor spillback valve. During FCCU startup the operating procedure was followed to minimize emissions to the extent possible. An incident investigation will result in recommendation items designed to prevent the recurrence of this event.
|Cause: An emergency shutdown device was triggered due to an incorrect reading on the Treating Reactor Bed 3 temperature indicator in the U215 hydrocracker which depressurized the unit to the South Ground Flare. In response to the shutdown, operations utilized the refinery slop line to deinventory the unit, routing material to Tank 500-6. Natural gas was inadvertently routed through the refinery slop line where Tank 500-6 received the vapor, causing a release through the tank seals.
Human factors also played a role in the incident.|
Notes: Root causes identified as Equipment Difficulty-Design Specs and Procedures Followed Incorrectly. At the time of the release, the emergency shutdown system was activated as designed shutdown the hydrocracker. Multiple recommendations have been identified to prevent a recurrence. The Tech Services Department at MPC has been tasked with mitigating the hazards of a single point of failure due to false temperature indication (anticipated completion 1/31/15). The operations department will develop and implement a system to verify all steps are completed and signed off when following procedures. A team will be developed to conduct a hazard analysis on the entire refinery slop system to implement necessary safeguards to prevent unwanted material from entering the slop system.
|Relief valve||Cause: Beginning at 1030 on 5/8/14, operations noticed the North Flare Stack SO2 analyzer was reading 20-30 lbs/hr. The source of emission was unknown at the time and the environmental department was notified. A courtesy notification was made at approx. 1930. The cause of the emission has since been determined to be a leaking relief valve (RV). This was an allowable emission under facility permit 2580-00013-V12. There were no known offsite impacts.|
Notes: Operations took multiple samples of the flare system to determine source of the material.
|U26 (Fluid Catalytic Cracking Unit Gas Con Unit)||Cause: While swapping the bottoms pump around pumps in U26 (Fluid Catalytic Cracking Unit Gas Con Unit) after maintenance, BPA flow was lost for approximately 20 minutes resulting in flaring from the debutanizer.
The flaring event began on April 29, 2014 at 10:47 adn stopped at 11:15.|
Notes: To contain the release, refinery workers attempted to start second pump, reduced the rate of the Crude Unit, Heavy Gas Oil Hydrotreater, HF Alkylation Unit, Gasoline Desulfurization and the Diesel Hydrotreater units until incident was under control. An incident investigation was conducted to determine the causes of the incident. Per this investigation, root causes were identified as Management System/SPAC Not Used/Enforcement Needs Improvement. Multiple recommendation items were identified to help prevent a recurrence of the event, including: 1) Update the generic pump switching guideline in each Operating Manual to include specific run verification steps (Complete by 11/2014), 2) Develop a "lessons learned" bulletin for the incident. Discuss how the causal factors lines up to result in the environment incident (Completed), 3) Review the "lessons learned" bulletin with operating personnel via a start-of-shift tool box meeting (Completed). Report on 9/9/14 states that an initial follow-up report was submitted on 5/6/14. This report is not available on the Louisiana Department of Environmental Quality's Electronic Data Management System (EDMS) as of 1/7/2015.
|Blowdown Settling Drum in Unit 05 Coker (HV-0705)||Cause: The Coke Drum was at a higher pressure than normal after the drum swap because HV-0705 was not opened from 40 to 70% prior to the swap. When swapping the offline drum to the blowdown tower, a much larger surge of flow occurred than normal due to the higher drum pressure. This caused the Blowdown Settling Drum to pressure up and its pressure control vent to open to the flare. There were no known offsite impacts.
It appears that the operator failed to follow appropriate drum swap procedures, causing the incident to occur.|
Notes: An incident investigation was conducted to determine the cause or causes of the incident. Per this investigation, the root cause was identified as a failure to complete/follow the steps in the Coke Drum Swap procedure. Multiple recommendation items have been identified to prevent a recurrence of this event. The MPC process control department has been tasked with implementing alarms and designing an interlock or control logic to prevent a quick increase in pressure to the Blowdown Settling Drum during a Coker Drum Swap (anticipated completion 9/15/14). The coke drum swap procedure will be modified by 7/7/14 to ensure the outside operator has verified and communicated with the board operator that each step of the procedure has been followed and completed. A training and auditing program will be instituted by 12/2/14 for field and board operators about the importance of procedural compliance.