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Marathon Ashland Petroleum (3165), Garyville

Releases of Hydrogen Sulfide

LDEQ Accident Number
Accident Date
Point Source(s) Notes Amount of Release
79431

2005-05-28
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.

Followup: Yes

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.
26.0
79261

2005-05-22
Thermal Oxidizer Cap (no EPN)
Cause: A local pressure controller in Unit 19 (Amine/Sour Water Stripper) closed due to high pressure and stopped amine flow to the Regenerator. Amine pump to Unit 15 (Heavy Gas Oil Hydrotreater) was tripped and the Unit 45 Sulfur Plant shut down due to the low amine acid flow. The sulfur plants all went off-ratio and began smoking 2 of the 3 Thermal Oxidizers , exceeding the opacity limit. The Unit 45 Sulfur Plant's Thermal Oxidizer then went below 900 F for app. 9 m which led to excess emissions of Hydrogen Sulfide.

Followup: Yes

Notes: An Air Monitoring Team was dispatched and no off-site impacts were found. Operations worked to get the Sulfur Plants back on ratio and minimized emissions. The incident is under investigation.
0.2 pounds
77730

2005-03-19
Distillate Hydroteating Unit
Cause: Leaking thermowell

Followup: No

Notes: Called inspector who found the leak; built encapsulation clamp; Report makes estimated leaks in pounds even though discharge was in drops
1.0 pounds
76432

2005-01-25
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.

Followup: No

Notes: Valve was closed within a minute of its opening.
1.0 pounds
89533

2006-07-26

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.

Followup: No

Notes: BELOW REPORTABLE QUANTITY.
0.1 pounds
87670

2006-05-08

Leaking flange gasket in distilate hydrotreater
Cause: During startup of the distillate hydrotreatmer, a flange gasket on a manway of the recycle gas amine scrubber was found leaking.

Followup:

Notes: BELOW REPORTABLE QUANTITY.
0.0 pounds
101968

2007-12-29
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.

Followup: No

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.
100086

2007-10-10

Cause: The packing in a lean amine bypass control valve blew out releasing amine and sour hydrogen gas to the atmosphere. To repair the valve the unit required depressurizing to the south flare

Followup: No

Notes: A high level incident investigation is underway
98487

2007-08-07
FCCO Cooling Tower and the North Flare
Cause: The PGC Aftercooler trim cooler was found leaking hydrocarbons into the FCCO cooling tower.

Followup: No

Notes: Claims emission was below RQ.
3.9 pounds
94388

2007-03-06
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.

Followup:

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.
0.0 pounds
90321

2007-01-03
North Flare
Cause:

Followup: No

Notes: Claims emission was below RQ. No Information Given
110989

2008-11-22
Hot Separator Overhead Fin Fan
Cause: Pin-hole leak in Unit 15's hot separator overhead fin fan.

Followup: No

Notes: Fin fan blocked in and leak repaired.
29.0 pounds
107208

2008-07-15
FCCU Tubing
Cause: Tubing from a flow orifice plate broke off and released LPG.

Followup: No

Notes: Unit start-up was aborted, all fired sources were extinguished and a fire monitor was opened.
103090

2008-02-15
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.

Followup: No

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.
4.5 pounds
102655

2008-01-28
North Flare (EQT162 / EIQ 83-70)
Cause: Coker Unit's Wet Gas Compressor shut down due to high level in the suction drum

Followup: No

Notes: Pending results of investigation
109.0 pounds
119673

2009-11-23
kerosene hydrotreater unit
Cause: During start-up of the kerosene hydrotreater unit (KHT), a bleeder valve o a piperack outside the unit was inadvertently left open, releasing gas into the atmosphere.

Followup: Yes

Notes: the line was isolated, and the valve was closed.
3.5 pounds
115720

2009-06-16
exchanger 05-1313
Cause: Pinhole leak from exchanger, 05-1313, caused a release of naphtha to the coker unit pad.

Followup: Yes

Notes: the exchanger was isolated, and contents were directed to the oily water sewer.
0.1 pounds
115595

2009-06-11
Hydrocarbon feed exchanger
Cause: While cleaning the exchanger a piece of tubing blew out causing a release of naptha to the exchanger pad.

Followup: Yes

Notes: Residual naphtha was washed into the oily sewer. The exchanger was isolated.
13.4 pounds
115506

2009-06-06
unit 15
Cause: Pin hole leak in he unit 15 HGO hot separator overhead fin fan.

Followup: Yes

Notes: Reportable quantities were no exceeded so no information was given. Letter from the refinery not available.
115394

2009-06-01
Unit 15 HGO hydrotreater
Cause: Pin-hole leak in unit 15's hot separator overhead fin fan.

Followup: Yes

Notes: Fin fan was blocked in and tube isolated.
20.0 pounds
112890

2009-01-23
flare
south flare
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

Followup: Yes

Notes: none, the releases went unnoticed until later.
89.1 pounds
128080

2010-12-09
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.

Followup: No

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.
0.6 pounds
127916

2010-11-29
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.

Followup: No

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.
8.2 pounds
125901

2010-08-22
North Ground Flare
Cause: Incident was the result of an electrical problem for the new production unit. A triplicated Triconex level indicator on the 1st stage suction drum malfunctioned, filled with liquid and tripped the wet gas compressor. Drum over-pressured which caused 205-PC-1511-V1 and V2 to open to the North Ground Flare. Released to air.

Followup: No

Notes: Reportable quantities for sulfur dioxide, hydrogen sulfide, and HRVOCs were exceeded. Remedial actions: The unit 205-delated coker reduced charge rate to minimize the release.
501.2 pounds
121645

2010-02-22
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.

Followup: No

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.
6.8 pounds
121405

2010-02-09
Unit 32 Stripper - Bleeder valve
Cause: Unit 5 coker sent a hydrogen sulfide emission to unit 33 sour water tank due to 3/4" bleeder valve being left open during the steaming out of Unit 32 Stripper.

Followup: No

Notes: BRQ. Refiney letter states that no reportable quantities were exceeded. Hot zone set up around the unit to prevent exposure to workers; report states "no known offsite impacts associated with the incident."
24.0 pounds
121169

2010-01-30
Unit 34 Sulfur Recovery Unit (EQT FUG037)
Cause: "While switching unit 34 tailgas from the Unity 34 Thermal Oxidizer to the Unit 20 Thermal Oxidizer, Unit 34 pressured up causing acid gas to back out of the low range air blower vent valve in Unity 34." Reportable quantity for Hydrogen Sulfide exceeded.

Followup: No

Notes: RQ. Reportable quantities were exceeded during this incident; detailed emissions report included. Refinery report states that "tailgas [was] switched back to the Unit 34 Thermal Oxidizer which corrected the problem immediately."
829.1 pounds
120841

2010-01-16
hydrocracker unit 215
hydrocracker unti 215
Cause: Leaking flange on new hydrocracker unit discovered at initial startup. "Authorized discharge" under existing permits.

Followup: No

Notes: BRQ. Refinery letter states that no reportable quantities were exceeded. Repair work begun immediately, air monitoring team dispatched to monitor area and fenceline, but found no detectable emissions.
120620

2010-01-15
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.

Followup: No

Notes: RQ. Faulty valve taken out of service & sent for repairs. RQ. Detailed release calculations attached to refinery letter.
6.4 pounds
134819

2011-10-22
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.

Followup: No

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.
0.1 pounds
132261

2011-07-07
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.

Followup: No

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.
10.6 pounds
132152

2011-06-30
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)

Followup: No

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.
0.0 pounds
131650

2011-06-04
Unit 222 Plant feed line
Cause: LDEQ report states Unit 222 Gas Plant feed line developed leak. Caused was cracked pipe.

Followup: No

Notes: RQ. Cracked pipe was replaced. State Police report indicates that the compressed flammable gas contained butane, methane, and propane. LDEQ and SPOC report only. No refinery letter included.
12.0 pounds
145377

2012-12-15
South Flare
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.

Followup: Yes

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.
395.0 pounds
143781

2012-10-12

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.

Followup: Yes

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.
1.3 pounds
143319

2012-09-23
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.

Followup: No

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.
0.1 pounds
140561

2012-06-16
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.

Followup: No

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.
1.0 pounds
136541

2012-01-14
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.

Followup: Yes

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.
7.6 pounds
152399

2013-11-14
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.

Followup: Yes

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.
152171

2013-11-06
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.

Followup: Yes

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.
5.0 pounds
150862

2013-09-07
Unit 222 Liquid feed pump (222-1501-02)
Cause: The emission point involved was a pinhole leak on the pump casing of 222-1501-02. Sour LPG leaked to the atmosphere causing the unit fixed monitor 222-AI-0019 to go in and out of alarm. Operators donned SCBA's to investigate and discovered a leak in the weld for the seal flush piping at the pump casing of 222-1501-02. The 222-1505-02 Liguid Feed Pump was out of service, leaving no spare. Emergency Shutdown of Unit 222 Sats Gas Plant (SGP) was activated.

Followup: No

Notes: Unit 222 Sats Gas Plant was shutdown when the emergency shutdown EIV-1 was closed from a remote location by the Shift Emergency Response Team (SERT). The pump was kept on until all liquid could be diverted to Unit 222 (Sats Gas Plant). The pump was then isolated for maintenance. Once the investigation is complete, recommendations will be implemented.
1.8 pounds
No LDEQ Reported

2013-07-24
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).

Followup: No

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.
6.7 pounds
149651

2013-07-15
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.

Followup: No

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.
3.6 pounds
149069

2013-06-11
Heat Exchanger 215-1304-02
Cause: On June 11, 2013, a small vapor leak developed on Heat Exchanger 215-1304-02. There were no offsite impacts.

Followup:

Notes: The area was cordoned-off. The exchanger head was hot bolted to secure the leak. No specific action is recommended for this incident.
7.1 pounds
148807

2013-05-19
Flow indicator 15FI0214
Cause: On May 19, the impulse lines on flow indicator 15FI0214 pulled away from the root valve. Blow taps on the valve blew off and released make-up hydrogen to the atmosphere. The causal factors leading to the failure of the tubing was Equipment Difficulty/Design Specs/Problem Not Anticipated. There were issues with the metallurgy of the tubing and the elevation of the transmitter in relation to the orifice taps.

Followup: Yes

Notes: Water from the fire monitors was sprayed on the release to help disperse the gas and prevent ignition. The board operator began depressurizing the unit through the dump valve in preparation for emergency shutdown. The line was isolated from the rest of the process unit to prevent further release of make-up hydrogen. To prevent recurrence, the following recommendations were made: 1) relocate the transmitter above the orifice taps on 15FE0214, and 2) replace stainless steel components of 15FT0214, including the impulse tubing with Hastelloy to prevent chloride-induced stress corrosion cracking. Also to tag the instrument tubing to indicate that the material is Hastelloy. Approximately 6.214 pounds of compressed flammable gas and 28 pounds of hydrogen sulfide were released.
28.8 pounds
148240

2013-04-20
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.

Followup: Yes

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.
0.8 pounds
147603

2013-03-25
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.

Followup: Yes

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.
36.7 pounds
146849

2013-02-21
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.

Followup: Yes

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.
27.1 pounds
146471

2013-02-07
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.

Followup: Yes

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.
611.0 pounds
No LDEQ Reported

2013-02-07
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.

Followup: No

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.
611.0 pounds
159790

2014-10-31
Sour Water Tanks in Units 33 and 233
Cause: The incident took place when fixed and personal H2S monitors were alarming in the area of the Sour Water Tank in Units 33 and 233. After some time, it was determined that the non-degassed Sour Water was allowed to bypass the surge drum due to high pressure, which routed this material directly to the Sour Water Storage Tanks. This resulted in a vapor release from the Sour Waste Tanks, A root cause analysis is being conducted to determine why the incident occurred. The refinery's fence line Ambient Air Monitors did not pick up any excess emissions at the time of the incident. The incident released approximately 620 pounds of Hydrogen Sulfide.

Followup: No

Notes: Air monitoring was conducted in the area around the tank. A perimeter was established around the affected area. The flow of sour water to the Sour Water Tanks was decreased ending the vapor release from the tanks. The root cause analysis will result in recommendations designed to prevent the recurrence of this event.
620.0 pounds
157829

2014-08-01

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.

Followup: Yes

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)
12.1 pounds
157392

2014-07-13
Unit 215, Hydrocracking Unit
Cause: While checking the 215-PSV-7006 cold HP separator for a leak, the downstream 12-inch block valve was closed and a leak developed around the valve bonnet gasket. The leak size was assumed to be 1/64-inch in thickness and 2 inches in width based on operator reports. Emission occurred in Unit 215, Hydrocracking Unit.

Followup: No

Notes: The line containing the valve was blocked in and the pressure reduced. An incident investigation will result in recommendation items designed to prevent the recurrence of this event.
4.6 pounds
157090

2014-06-27
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.

Followup: Yes

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].
10.6 pounds
157090

2014-06-27
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.

Followup: Yes

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].
10.6 pounds
156739

2014-06-10
pipe containing crude oil in Unit 10 - Crude unit
Cause: A 3/4-inch process pipe containing crude oil connecting the desalters sheared causing loss of containment. Crude oil exited the pipe and was collected in the oily water sewer.

Followup: No

Notes: The piping was blocked in to eliminate the amount of crude oil leaking from the piping. All crude that leaked landed on the concrete slab in the unit and was collected by washing it into the oily water sewer.
10.8 pounds
15660

2014-06-07
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.

Followup: No

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.
0.4 pounds
156198

2014-05-23
Tank 5000-6
U215 hydrocracker
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.

Followup: Yes

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.
21.3 pounds