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Phillips 66 (2418), Belle Chasse

Causal Factor: Process Upset

LDEQ Accident Number
Accident Date
Point Source(s) Notes Amount of Release
92240

2006-11-23
301-D-3 FCC Regenerator Flue Gas Bypass Stack; 308F-D-1 Low Pressure Flare; 308F-D-2 High Pressure Flare
Cause: The FCC process control system malfunctioned causing upset operating conditions at the FCC Unit. This malfunction caused an immediate and unecpected shutdown of the entire FCC Unit.

Followup: yes

Notes: According to the report: "Although preventative maintenance procedure exist, conditions of this type cannot be anticipated. An investigation is continuing to determine the root cause of this accident."
Carbon Monoxide: 7,169.0 pounds
Hydrocarbon: 200.0 pounds
Hydrogen Sulfide: 7.0 pounds
Nitrogen Oxide: 36.1 pounds
Sulfur Dioxide: 606.0 pounds
91249

2006-10-10
308F-D-1 Low Pressure Flare
Cause: The water boot control valvve for the straight run debutanizer malfunctioned and at the same time the water boot level indicator malfunctioned and began transmitting false levels

Followup: No

Notes: Stabilized using the manual by-pass and a replacement control valve was ordered and hot shot shipped to the refinery. The replacement control valve was installed that same evening. The level indicator was checked, cleaned and placed back in service.
Hydrocarbon: 904.8 pounds
90872

2006-09-25
410 PSV 061
Cause: Final repssure increase on the Enbridge Purchased Fuel Gas line resulted in an out of sync system dynmics which resulted in causing the Process Safety Valve to lift slightly

Followup: No

Notes: Immediately lowered the PFG system's pressure which reseated PSV 061
Methane/Ethane Mixture: 11,605.0 pounds
90011

2006-08-15
308F-D-2 High Pressure Flare
Cause: During restart of Alkylation Unit a pressure surge triggered an automatic shutdown. Pressure safety valves relieved on 491V8.

Followup: No

Notes: Plant personnel stabilized unit operations to prepare AU 491 for restart
Hydrocarbon: 2,812.0 pounds
Nitrogen Oxide: 112.7 pounds
89113

2006-07-08
308F-D-2 High Pressure Flare
Cause: The Process Safety Valve relieved to the HP flare causing the Pressure Swing Absorption unit to trip off line.

Followup: No

Notes: The entire 1792 Unit including the PSA portion of the unit was shutdown to allow inspection of the hot spot in the heater.
Hydrocarbon: 25.1 pounds
Nitrogen Oxide: 11.8 pounds
88719

2006-06-19
308F-D-2 High Pressure Flare
Cause: The Pressure Swing Adsorption Unit tripped off line due to leaking of the Repssure Safety Valve to the HP Flare System.

Followup: No

Notes: PSV was isolated from the unit. An investigation is continuing to determine the root cause of this accident.
Hydrocarbon: 848.0 pounds
Nitrogen Oxide: 60.8 pounds
Sulfur Dioxide: 1.0 pounds
87421

2006-04-26
308F-D-1 Low Pressure Flare
Cause: Problems with the coke cutting system required a switch of drums which reduced the flow to the compressor and caused a compressor kickback valve to open to the flare.

Followup: No

Notes: Pressures were stabilized and the valve was closed.
Hydrocarbon: 159.0 pounds
Hydrogen Sulfide: 19.0 pounds
Nitrogen Oxide: 16.6 pounds
Sulfur Dioxide: 1,895.0 pounds
101672

2007-12-13

412-A-FF
Cause: The Pressure Safety Valve relieved to the atmosphere for approximately 15 minutes after being installed. THe PSV is designed to open enough as requeired to relieve in an overpressure situation. It has a set pressure for Tank 503 set to approx. 83 psig. During this event it was noted that pressure in Tank 503 remained at approx. 30 psig and the set pressure for the PSV was never reached. There is no explanation given for why this might have occurred.

Followup: Yes

Notes: The adjacent PSV 100 PSV 15B was placed into service as PSV 15A was blocked in and isolated to minimize the release.
Isobutane: 15,042.0 pounds

100489

2007-10-24
1792-FF
Cause: Compressor trip caused by a high level signal from its suction drum which caused a pressure safety valve release.

Followup: Yes

Notes: Refinery claims that preventative maintenance could not have prevented this accident.
Benzene: 56.2 pounds
Flammable Gas: 1,725.2 pounds
96572

2007-05-28
100-Pressure Safety Valve-5A
Cause: Pressure relief valve(100-PSV-5A) on sphere T-205 relieved prematurely and unexpectedly, releasing Light Hydrocarbon Vapors (VOCs).

Followup: Yes

Notes: The valve was blocked and removed by maintenance for repair.
Light Hydrocarbons: 792.0 pounds
106796

2008-06-28
308F-D-1 (Low Pressure Flare), 591-D-21-X (SRU Incinerator Stack) FLARE
Cause:

Followup: Yes

Notes: Acid Gas flaring due to 592-H-1 heater going offline after loss of flame caused by pressure fluctuation in the Sour Water Stripper vessel affecting feed stream quality to SRU-592 Unit. 592-H-1 heater relit and brought back on line.
Sulfur Dioxide: 2,701.6 pounds
119864

2009-12-05

No information given
Cause: The 592 Sulfur Recovery Unit (SRU) has 3 combustion air blowers. Usually, 2 are on line. On 12/5, one of the two operating blowers tripped due to a thermal overload. This drop in air discharge pressure activated the Low Combustion Air Pressure alarm which shutdown combustion in the SRU Reaction Furnace. This activated the Sour Water Stripper (SWS).

Followup: No

Notes: The refinery initiated "sulfur-shedding" procedures until SRU could be brought back online.
Sulfur Dioxide: 241.0 pounds




116329

2009-07-09
410-PSV-061
Cause: Pressure in the refinery instrument air supply system decreased unexpectedly which resulted in the loss of pressure control at the Enbridge purchased fuel gas control station (on the property of the refinery). This loss of pressure control caused the PSV (410-PSV-061) to lift until proper pressure within the instrument air system could be restored.

Followup: No

Notes: Immediately regained control of the plant fuel gas system manually. "No offsite impact was noted."
Methane/Ethane Mixture: 12,284.0 pounds
122118

2010-03-13
no information given
Cause: "process unit upset caused to go to flare"

Followup: No

Notes: DEQ report only in this file; no refinery letter.

134825

2011-10-24
Low Pressure Flare (308F-D-1)
Cause: The Control Board Operator received a high temperature seal oil alarm from the Fluidized Catalytic (FCC) 1291-K-2 Compressor equipment. Operators were instructed to back flush the seal oil coolers to remove any foulant material which may have accumulated and contributed to seal oil system's high temperature. During the back flushing procedure the seal oil operating differential pressure increased due to the increased viscosity of the cooler oil. Unexpectedly the seal oil's differential pressure began to rapidly decrease below the trip pressure of the compressor causing it to trip off-line. When the 1291-K-2 compressor trips off-line, the FCC fractionator overhead flare valve opens and relieves its gases to the Low Pressure Valve (308F-D-1) until the compressor can be started.

Followup: No

Notes: The compressor was restarted shortly after the pressure alarm was cleared and proper differential pressures were reestablished within the compressor's seal oil system. The failed pressure regulator was replaced to minimize repeating another compressor trip due to erratic pressure readings.
Sulfur Dioxide: 281.0 pounds
136882

2012-02-01
1391-FF (1391-PSV-009)
Cause: There was an unexpected increase in the Depantanizer tower's overhead pressure causing PSV-009 to relieve. This was the result of the shutdown of the reboiler due to high burner pressure.

Followup: No

Notes: The reboiler (1391-H-4) temperature was lowered which lowered the pressure in the Depantanizer Tower allowing 1391-PSV-009 to reseat. There is no LDEQ report and no SPOC report attached to this file. 19,570 pounds released
Hydrogen: 485.7 pounds
Methane: 1,366.7 pounds
Ethane: 4,630.4 pounds
Propane: 6,470.4 pounds
Butane: 2,395.8 pounds
1-Butene: 2,135.6 pounds
Butene: 9.7 pounds
2,2-Dimethylpropane: 7.2 pounds
Pentane: 1,983.2 pounds
3-Methyl-1-Butene: 1.3 pounds
trans-2-Pentene: 0.5 pounds
2-Methyl-2-Butene: 0.5 pounds
Nitrogen: 71.5 pounds
1-Pentene: 0.8 pounds
2-Methyl-1-Butene: 2.4 pounds
Benzene: 5.4 pounds
n-Butane: 3.3 
156589

2014-06-09
Sulfur Recovery Unit Incinerator (2774-V3)
Cause: On June 9, 2014 the Sour Water Stripper (SWS) Unit experienced unexpected pressure swings and fluctuating rates in its overhead system resulting in reduced unit efficiency in both the 592 Sulfur Recovery Unit (SRU) the Tail Gas Treater Unit (TGT) subsequently causing an increase in sulfur dioxide (SO2) emissions at the TGT's incinerator (591-D-21X) based upon the stack So2 CEMs monitor. Preliminary information from the investigation indicated an unexpected SWS feed composition change adversely impacted SRU and TGT operation resulting in elevated SO2 emissions at the TGT's incinerator. Sour water production from various refinery units were reduced in order to stabilize SWS operations and improve sulfur conversion rates at the SRU, which improved SO2 emissions at the incinerator. A Root Cause Analysis (RCA) investigation was completed and revealed that an unexpected slug of hydrocarbon and hydrocarbon particulate in the sour water feed to the Sour Water Stripper (SWS) Unit. This hydrocarbon was unexpectedly trapped in the feed line between T-101 and the SWS Unit and was released as Tank-101's feed valve was opened during the initial steps of the sour water tank swap. This hydrocarbon contamination resulted in unstable SWS overhead operations that produced pressure and flow swings which further deteriorated proper sulfur recovery at the 592 SRU Unit. Loss of proper sulfur recovery at the SRU Unit resulted in H2S breakthrough at the Tail Gas Treater (TGT) and burning of this H2S in the SRU Incinerator stack causing So2 emissions to spike. As part of determining all contributing causes to this incident, further investigation revealed that the preparations for using Tank-101 for use as the alternative sour water tank may have contributed to the event. It is suspected that the required flushing of the alternative sour water feed tank's line in preparation for use may have unexpectedly trapped a slug of hydrocarbon in the flush piping. Another contributing factor to the incident was the fact that there was no available sampling point in the flush circuit which would have allowed confirmation of good hydrocarbon separation from the sour water as well as no hydrocarbon particulate.

Followup: Yes

Notes: Immediate corrective action: Immediately implemented sour gas shedding by reducing rates from refinery units that produce sour water. SRU operations were stabilized and incinerator emissions were reduced. A Root Cause Analysis (RCA) identified the following measures to prevent recurrence: 1) Improve sour water line flushing procedure to ensure optimum sour water quality and to minimize feed dead legs in the lines that can trap hydrocarbon and hydrocarbon containments, 2) Evaluate lining up the SWS overhead gases to the Flare Gas Recovery System when swapping sour water feed tanks.
Sulfur Dioxide: 732.0 pounds
156142

2014-05-21
SRU Incinerator (591-D-21X) and Low Pressure Flare (308F-D-1)
Cause: Sulfur recovery units 591 and 592 experienced an unexpected operational upset that affected both unit flows and pressures. The sulfur conversion rates of both SRUs dropped off, subsequently overloading the tail gas treater (TGT) unit. The refinery implemented its emergency sulfur shedding procedures. The shedding of the refinery acid gas producers allowed the shutdown of SRU Unit 591. With SRU 591 shut down, the TGT unit tripped offline unexpectedly due to erratic pressure and flow swings. SRU 592 remained in operation, running at reduced rates. Its gases were routed to the SRU incinerator (591-D-21X). Higher-than-normal incinerator temperatures created safety concerns; therefore, the refinery shut down SRU 592 for a brief period of time and flared the remaining acid gas to the Low Pressure Flare (308F-D-1). Further acid gas shedding was immediately implemented with operational adjustments that included shutting down both of the refinery's diesel hydrotreaters, the delayed coker unit, while cutting the crude unit and FCC unit feed rates to minimum and charging feed stocks to both the crude and FCC units. When safe operating conditions were re-established at the SRU incinerator, Unit 592 was brought back online at reduced rates, and its tail gases remained routed to the SRU incinerator. On 5/22, it was determined that the Quench Tower (308-V-31) in the TGT train had unexpected sulfur pluggage, which had to be removed for the TGT to properly function and come back online. A repair plan resolving TGT pluggage was implemented and completed with the TGT resuming normal operations on 5/25. Continuous air monitoring was conducted at the fenceline throughout the event. Attached emissions calculations show that 750 pounds of sulfur dioxide were emitted from the SRU incinerator on 5/21, 62,500 pounds from acid gas flaring on 5/21, and 26,425 pounds from the SRU incinerator on 5/25. A Root Cause Analysis (RCA) investigation was completed and revealed there was an unexpected pluggage in the sulfur product line leading from the SRU 592 Unit to the primary sulfur storage tank. Several days prior to the incident, the primary sulfur storage tank had experienced problems with its pumping system that required several days to repair resulting in higher than normal use of the secondary sulfur storage tank to complete the loading and filling of sulfur trucks. When repairs to the pumping system were completed, the sulfur product piping of the SRU 592 Unit was rerouted from the secondary sulfur storage tank back to the primary sulfur storage tank. The initial SRU pressure increase coincided with this rerouting and the pluggage in the sulfur product piping led to the gradual buildup of molten sulfur in the condensers, reduced cross sectional area of the flow path and increased operating pressure of the SRU 592 Unit. Many operational changes (such as shifting of acid gas loads as well as sulfur shedding) were attempted to compensate for the pressure rise but were not successful. In determining all contributing causes to this incident, further investigation revealed that the slow responses to the rapid pressure and air rate changes by the air demand analyzer, the Tail Gas Treater (TGT) hydrogen analyzer, and the main air ratio controller led to out of balance air to gas ratios causing overloading of the TGT Unit, preventing it to convert sulfur dioxide in to hydrogen sulfide. This phenomenon ultimately resulted in elemental sulfur precipitation in the TGTs quench tower, leading to a total shutdown of the TGT until the quench tower could be repaired.

Followup: No

Notes: Immediate corrective action included implementation of the refinery's sulfur shedding plan reducing the sulfur load to the Sulfur Recovery Units. The sulfur shedding plan is documented in the refinery's Consent Decree required Preventative Maintenance and Operability (PMO) plan. The following corrective actions were identified after a Root Cause Analysis was conducted: 1) Develop methods to detect and identify line pluggage in sulfur product piping systems of the SRU Units 2) Conduct a refresher class with operators regarding operation of all equipment in the sulfur recovery system. Include the lessons learned from this incident as part of this review. Note that two different durations are given for this event. In the attachment, the event was said to have occurred for 88.1 hours. Earlier in the document, the figure is given as 5,870 minutes, which converts to 97.8 hours.
Sulfur Dioxide: 89,675.0 pounds