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Valero (1238), Meraux

Releases of Sulfur Dioxide

LDEQ Accident Number
Accident Date
Point Source(s) Notes Amount of Release
81285

2005-08-15
#3 Sulfur Recovery Unit #5 - 00
South Flare - EPN # 3 - 77
Cause: Malfunction of temperature monitor resulted in a shutdown

Followup: No

Notes: There were 28 complaint calls made to the refinery!
27,860.0 pounds
81285

2005-08-15
#3 Sulfur Recovery Unit #5 - 00
South Flare - EPN # 3 - 77
Cause: Malfunction of temperature monitor resulted in a shutdown

Followup: No

Notes: There were 28 complaint calls made to the refinery!
341.0 pounds
81253

2005-08-12
South Flare - EPN # 3 - 77
Cause: Fluctuating acid gas rates from steam system

Followup: No

Notes: Turned down the system and got the flow to where it should be.
1,535.0 pounds
81118

2005-08-09
#3 Sulfur Recover Unit Incinerator (#5-00)
Cause: A faulty solenoid in the main curner gas control valve caused the release

Followup: No

Notes: They replaced the part
1,164.0 pounds
80945

2005-07-31
#2 Sulfur Recover Unit Incinerator (1-93)
No information given
North Flare 20-72
Cause: Malfunction in the power supply to the control panel's Process Logic Controller card

Followup: No

Notes: Followed procedures for emergency shutdown.
82,094.0 pounds
80945

2005-07-31
#2 Sulfur Recover Unit Incinerator (1-93)
No information given
North Flare 20-72
Cause: Malfunction in the power supply to the control panel's Process Logic Controller card

Followup: No

Notes: Followed procedures for emergency shutdown.
4,427.0 pounds
80591

2005-07-18
South Flare - EPN # 3 - 77
Cause: Solids in the #2 SWS Overhead Receiver plugged the vessel's suction line

Followup: No

Notes: They steamed the lines to clear them.
12,069.0 pounds
80466

2005-07-11
South Flare
Cause: Maintenace bypass switch on the UPS unit malfunctioned.

Followup: No

Notes: The report has conflicting information about duration of the event and the point source. Page 2 says it was the north flare and the SRU Incinerator, but the p. 4 emissions details say south flare. The info entered here is from the last page.
9,809.0 pounds
80323

2005-07-06
#2 Sulfur Recovery Unit Incinerator #1-93
#3 Sulfur Recovery Unit Incinerator #5-00
No information given
North Flare
South Flare
Cause: On 7/6/05 Murphy Oil experienced a refinery-wide power interruption. During the shutdown and ensuing startup, the refinery experienced elevated sulfur dioxide and intermittent particulate emissions at the flares and the Sulfur Recovery Unit incinerator stacks. The power outage was apparently the result of high winds generated by Tropical Storm Cindy.

Followup: No

Notes: Immediate action was to safely get the units stabilized and try to avoid damage to equipment during the emergency shutdown. To ensure a safe restart, the refinery purged rich amine from #1 and #2 Amine units and the #2 Sour Water Stripper to the flares. The refinery minimized SO2 emissions during startup by having the #2 and #3 SRUs pre-heated prior to introduction of acid gas. Received two citizen complaints. Took steps to minimize emissions for the re start.
11,804.0 pounds
80323

2005-07-06
#2 Sulfur Recovery Unit Incinerator #1-93
#3 Sulfur Recovery Unit Incinerator #5-00
No information given
North Flare
South Flare
Cause: On 7/6/05 Murphy Oil experienced a refinery-wide power interruption. During the shutdown and ensuing startup, the refinery experienced elevated sulfur dioxide and intermittent particulate emissions at the flares and the Sulfur Recovery Unit incinerator stacks. The power outage was apparently the result of high winds generated by Tropical Storm Cindy.

Followup: No

Notes: Immediate action was to safely get the units stabilized and try to avoid damage to equipment during the emergency shutdown. To ensure a safe restart, the refinery purged rich amine from #1 and #2 Amine units and the #2 Sour Water Stripper to the flares. The refinery minimized SO2 emissions during startup by having the #2 and #3 SRUs pre-heated prior to introduction of acid gas. Received two citizen complaints. Took steps to minimize emissions for the re start.
12,816.0 pounds
80323

2005-07-06
#2 Sulfur Recovery Unit Incinerator #1-93
#3 Sulfur Recovery Unit Incinerator #5-00
No information given
North Flare
South Flare
Cause: On 7/6/05 Murphy Oil experienced a refinery-wide power interruption. During the shutdown and ensuing startup, the refinery experienced elevated sulfur dioxide and intermittent particulate emissions at the flares and the Sulfur Recovery Unit incinerator stacks. The power outage was apparently the result of high winds generated by Tropical Storm Cindy.

Followup: No

Notes: Immediate action was to safely get the units stabilized and try to avoid damage to equipment during the emergency shutdown. To ensure a safe restart, the refinery purged rich amine from #1 and #2 Amine units and the #2 Sour Water Stripper to the flares. The refinery minimized SO2 emissions during startup by having the #2 and #3 SRUs pre-heated prior to introduction of acid gas. Received two citizen complaints. Took steps to minimize emissions for the re start.
53.0 pounds
80323

2005-07-06
#2 Sulfur Recovery Unit Incinerator #1-93
#3 Sulfur Recovery Unit Incinerator #5-00
No information given
North Flare
South Flare
Cause: On 7/6/05 Murphy Oil experienced a refinery-wide power interruption. During the shutdown and ensuing startup, the refinery experienced elevated sulfur dioxide and intermittent particulate emissions at the flares and the Sulfur Recovery Unit incinerator stacks. The power outage was apparently the result of high winds generated by Tropical Storm Cindy.

Followup: No

Notes: Immediate action was to safely get the units stabilized and try to avoid damage to equipment during the emergency shutdown. To ensure a safe restart, the refinery purged rich amine from #1 and #2 Amine units and the #2 Sour Water Stripper to the flares. The refinery minimized SO2 emissions during startup by having the #2 and #3 SRUs pre-heated prior to introduction of acid gas. Received two citizen complaints. Took steps to minimize emissions for the re start.
226.0 pounds
80276

2005-07-03
#3 Sulfur Recover Unit Incinerator (#5-00)
Cause: Makeup gas compressor in the Hydocracking Unit malfunctioned due to a lightening strike

Followup: Not Applicable

Notes: Followed standard procedures to re start operations.
288.0 pounds
79999

2005-06-21
No information given
South Flare
Cause: Wire shorted

Followup: No

Notes: There was also a power failure - seem to be 2 causes of the problem. The release took place on two days - 6/21 and then 126 lbs on 6/23 when they re started. There were seven complaint calls.
38,664.0 pounds
79847

2005-06-15
South Flare - EPN # 3 - 77
Cause: Malfunction of the steam trap allowed condensate into the Amine unit reboiler, triggering a series of events resulting in the incident

Followup: No

Notes: Steam trap repaired
20,520.0 pounds
79446

2005-05-30
South Flare - EPN # 3 - 77
Cause: Blown fuses at the hydrotreater charge pump

Followup: No

Notes: Faulty fuses replaced
3,133.0 pounds
79082

2005-05-16
#3 Sulfur Recover Unit Incinerator (#5-00)
Cause: Malfunctioning valve positioner on the main air valve

Followup: No

Notes: The valve positioner has been replaced. Appear to be 2 incident #'s. The second is. 05-03210
1,351.0 pounds
77899

2005-03-30
#3 Sulfur Recover Unit Incinerator (#5-00)
South Flare - EPN # 3 - 77
Cause: Malfunction of the level transmitter on the #2 Amine Acid Gas Knockout Drum

Followup: No

Notes: Replaced level transmitter.
14,048.0 pounds
77899

2005-03-30
#3 Sulfur Recover Unit Incinerator (#5-00)
South Flare - EPN # 3 - 77
Cause: Malfunction of the level transmitter on the #2 Amine Acid Gas Knockout Drum

Followup: No

Notes: Replaced level transmitter.
248.0 pounds
77748

2005-03-21
#3 Sulfur Recover Unit Incinerator (#5-00)
South Flare - EPN # 3 - 77
Cause: A fuse was blown during the replacement of a faulty solenoid on the city gas control valve at the incinerator

Followup: No

Notes: There appear to be two state police #'s for this report. The other is 05-01888. Solenoid failure and fuse malfunction have been dealt with, as these were the cause of the problems.
11,067.0 pounds
77748

2005-03-21
#3 Sulfur Recover Unit Incinerator (#5-00)
South Flare - EPN # 3 - 77
Cause: A fuse was blown during the replacement of a faulty solenoid on the city gas control valve at the incinerator

Followup: No

Notes: There appear to be two state police #'s for this report. The other is 05-01888. Solenoid failure and fuse malfunction have been dealt with, as these were the cause of the problems.
159.0 pounds
77705

2005-03-20
#3 Sulfur Recovery Unit
Bypass of #2 Amine gas to the SOUTH FLARE
Cause: Faulty alarm in the Distributed Control System

Followup: No

Notes: Reviewed all of its alarm systems.
319.0 pounds
77705

2005-03-20
#3 Sulfur Recovery Unit
Bypass of #2 Amine gas to the SOUTH FLARE
Cause: Faulty alarm in the Distributed Control System

Followup: No

Notes: Reviewed all of its alarm systems.
10,625.0 pounds
77339

2005-03-03
North Flare
North Flare 20-72
Cause: automatic shutdown of the Sour Gas Compressor in the Distillate Hydrotreater

Followup: Yes

Notes: Says they will submit a more complete report by Monday, March 14
705.0 pounds
77339

2005-03-03
North Flare
North Flare 20-72
Cause: automatic shutdown of the Sour Gas Compressor in the Distillate Hydrotreater

Followup: Yes

Notes: Says they will submit a more complete report by Monday, March 14
705.0 pounds
77051

2005-02-21
#2 Sulfur Recover Unit Incinerator (1-93)
Cause: When they tried to re start after the following problem, they found a number of "mechanical problems," like plugged packing and a leak in a valve

Followup: No

Notes: Two incidents were listed in one report
15,503.0 pounds
77058

2005-02-19
#2 Sour Gas Incinerator (emissions were routed there)
Cause: in the Tail Gas Treater. The notes say that there are maintenance problems, but that's because of troubles with the equipment.

Followup: Yes

Notes: Follow up report promised within five days.
125.0 pounds
77051_a

2005-02-19
North Flare 20-72
Cause: Hydorbarbon breakthrough from the Amine Unit to the SRU due to plugging in the Tail Gas Treater (TGT)

Followup: No

Notes: Replaced packing and a valve in the Tail Gas Treater
38,367.0 pounds
77020

2005-02-18
North Flare 20-72
Cause: of the Sour Gas Compressor in the Distillate Hydrotreater

Followup: No

Notes: No information Given
13,397.0 pounds
76868

2005-02-11
No information given
Cause: Power failure due to Entergy's loss of power

Followup: Yes

Notes: Refinery wide power outage that damaged several units. More info is supposed to be provided in follow up report within ten days. See 3/11/05 for details.
05-BB013-3696

2005-02-11
#2 Sulfur Recover Unit Incinerator (1-93)
#3 Sulfur Recovery Unit Incinerator (5-00)
North Flare 20-72
South Flare - EPN # 3 - 77
Cause: Power failure due to Entergy's loss of power

Followup: No

Notes: There are two state police numbers on this report thought only the 00969 one seems to be discussed. I have thus listed only that #. This is a follow up report for the power failure on 2/11. It does say smoke was intermittent, perhaps all releases were. The report also notes a re start date of 2/20 but there are no emissions listed for that date. The report on 4/4/05 details the emissions amounts for S02."
488.0 pounds
05-BB013-3696

2005-02-11
#2 Sulfur Recover Unit Incinerator (1-93)
#3 Sulfur Recovery Unit Incinerator (5-00)
North Flare 20-72
South Flare - EPN # 3 - 77
Cause: Power failure due to Entergy's loss of power

Followup: No

Notes: There are two state police numbers on this report thought only the 00969 one seems to be discussed. I have thus listed only that #. This is a follow up report for the power failure on 2/11. It does say smoke was intermittent, perhaps all releases were. The report also notes a re start date of 2/20 but there are no emissions listed for that date. The report on 4/4/05 details the emissions amounts for S02."
8,095.0 pounds
05-BB013-3696

2005-02-11
#2 Sulfur Recover Unit Incinerator (1-93)
#3 Sulfur Recovery Unit Incinerator (5-00)
North Flare 20-72
South Flare - EPN # 3 - 77
Cause: Power failure due to Entergy's loss of power

Followup: No

Notes: There are two state police numbers on this report thought only the 00969 one seems to be discussed. I have thus listed only that #. This is a follow up report for the power failure on 2/11. It does say smoke was intermittent, perhaps all releases were. The report also notes a re start date of 2/20 but there are no emissions listed for that date. The report on 4/4/05 details the emissions amounts for S02."
56,871.0 pounds
76817

2005-02-09
North Flare 20-72
Cause: of the Sour Gas Compressor in the Distillate Hydrotreater

Followup: No

Notes: They replaced gaskets. Note the second letter in the file that corrects the incident date in the original letter.
8,250.0 pounds
76189

2005-01-14
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: in the #3 Sulfur Recovery Unit. There was a malfunction in the main air valve.

Followup: No

Notes: There were two separate incidents in this one report (see the next row). The refinery is installing redundant equipment to upgrade reliability of air valve.
45,996.0 pounds
76189

2005-01-14
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: in the #3 Sulfur Recovery Unit. There was a malfunction in the main air valve.

Followup: No

Notes: There were two separate incidents in this one report (see the next row). The refinery is installing redundant equipment to upgrade reliability of air valve.
8,854.0 pounds
76189

2005-01-14
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: in the #3 Sulfur Recovery Unit. There was a malfunction in the main air valve.

Followup: No

Notes: There were two separate incidents in this one report (see the next row). The refinery is installing redundant equipment to upgrade reliability of air valve.
1,262.0 pounds
76189

2005-01-14
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: in the #3 Sulfur Recovery Unit. There was a malfunction in the main air valve.

Followup: No

Notes: There were two separate incidents in this one report (see the next row). The refinery is installing redundant equipment to upgrade reliability of air valve.
759.0 pounds
76176

2005-01-12
#2 Sulfur Recovery Unit Incinerator #1-93
Cause: A hole developed in the chamber wall of the #2 Tail Gas Treater

Followup: No

Notes: The wall was patched.
1,647.0 pounds
76176

2005-01-12
#2 Sulfur Recovery Unit Incinerator #1-93
Cause: A hole developed in the chamber wall of the #2 Tail Gas Treater

Followup: No

Notes: The wall was patched.
540.0 pounds
76080

2005-01-10
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: A contract programmer set the equipment so that it was "too sensitive" to process paremeters and thus triggered a safety shut down of the unit.

Followup: No

Notes: Two incidents were reported in one letter (see next row). The original incident released a big volume of SO2 through the South Flare; restarting produced the emissions in the Tail Gas Treater. The report specifically says that this was NOT due to human error (despite the programmer's setting)
29,362.0 pounds
76080

2005-01-10
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: A contract programmer set the equipment so that it was "too sensitive" to process paremeters and thus triggered a safety shut down of the unit.

Followup: No

Notes: Two incidents were reported in one letter (see next row). The original incident released a big volume of SO2 through the South Flare; restarting produced the emissions in the Tail Gas Treater. The report specifically says that this was NOT due to human error (despite the programmer's setting)
239.0 pounds
76080

2005-01-10
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: A contract programmer set the equipment so that it was "too sensitive" to process paremeters and thus triggered a safety shut down of the unit.

Followup: No

Notes: Two incidents were reported in one letter (see next row). The original incident released a big volume of SO2 through the South Flare; restarting produced the emissions in the Tail Gas Treater. The report specifically says that this was NOT due to human error (despite the programmer's setting)
8,595.0 pounds
76080

2005-01-10
#3 Sulfur Recovery Unit Incinerator
South Flare - EPN # 3 - 77
Cause: A contract programmer set the equipment so that it was "too sensitive" to process paremeters and thus triggered a safety shut down of the unit.

Followup: No

Notes: Two incidents were reported in one letter (see next row). The original incident released a big volume of SO2 through the South Flare; restarting produced the emissions in the Tail Gas Treater. The report specifically says that this was NOT due to human error (despite the programmer's setting)
212.0 pounds
75946

2005-01-03
#3 Sulfur Recovery Unit
Cause: Conducted a bypass of the Tail Gas Treater as part of routine start up

Followup: No

Notes: BELOW REPORTABLE QUANTITIES
288.0 pounds
75954

2005-01-03
No information given
South Flare - EPN # 3 - 77
Cause: Surge of acid gas feed during hydrocracker startup

Followup: No

Notes: There is no reason given for the hydrobracker startup. Two incidents were reported in one letter.
37,752.0 pounds
75954

2005-01-03
No information given
South Flare - EPN # 3 - 77
Cause: Surge of acid gas feed during hydrocracker startup

Followup: No

Notes: There is no reason given for the hydrobracker startup. Two incidents were reported in one letter.
12,064.0 pounds
76080_a

0200-01-10
South Flare
Sulfur Recovery Unit Incinerator #3
Cause: It was hard to figure out what is going on. The report stated that it happened because they re started the Sour Water Stripper but it didn't say why it needed to be re started.

Followup: No

Notes: Note that this is additional information to the incident reported on 1.10.05
40,761.0 pounds
76080_a

0200-01-10
South Flare
Sulfur Recovery Unit Incinerator #3
Cause: It was hard to figure out what is going on. The report stated that it happened because they re started the Sour Water Stripper but it didn't say why it needed to be re started.

Followup: No

Notes: Note that this is additional information to the incident reported on 1.10.05
451.0 pounds
92563

2006-12-11
#2 SRU incinerator (1-93#)
2 SRU incinerator (1-93#)
Cause: TGT startup - melt out of the two towers during which time the TGT was bypassed

Followup: No

Notes: SERC Incident # 06-07489. Excess emmissions was part of standard procedure for operating procedures to do startup. Used acid gas to mitigate the env. Impact of acid gas in the env.
393.0 pounds
92563

2006-12-11
#2 SRU incinerator (1-93#)
2 SRU incinerator (1-93#)
Cause: TGT startup - melt out of the two towers during which time the TGT was bypassed

Followup: No

Notes: SERC Incident # 06-07489. Excess emmissions was part of standard procedure for operating procedures to do startup. Used acid gas to mitigate the env. Impact of acid gas in the env.
583.0 pounds
89735

2006-08-03
South Flare (EPN #20-72)
Cause: #3 SRU Malfunction- the ## TGT Bypass Valve opened intermittently to the S. Flare, releasing Sulfur Dioxide. Resulting from a malfunction in the Air Demand Analyzer, b/c of a loss of steam due to pluggage in the steam line.

Followup: Yes

Notes: SERC incident # 06-4881. Immediately looked for the cause and when discovered plugged the line, cleared this small diameter steam line. Solids removed from the line suggest corrosion from Katrina. Looking at the possibility that re-routing this steam line may help prevent recurrence.
1,540.0 pounds
89284

2006-07-16
#2 SRU incinerator (EPN #1-93)
#3 SRU incenerator
North Flare (EPN #20-72)
South Flare #20-72
Cause: Malfunction at the 450# bOiler Feed Water Discharge Check Valve leading to an automatics safety shutdown of SRU #2,3

Followup: No

Notes: SERC incident # 06-04451. Acid gas was routed to the flares and implimenting the refinery's Sulfur Shedding Plan
17,708.0 pounds
89284

2006-07-16
#2 SRU incinerator (EPN #1-93)
#3 SRU incenerator
North Flare (EPN #20-72)
South Flare #20-72
Cause: Malfunction at the 450# bOiler Feed Water Discharge Check Valve leading to an automatics safety shutdown of SRU #2,3

Followup: No

Notes: SERC incident # 06-04451. Acid gas was routed to the flares and implimenting the refinery's Sulfur Shedding Plan
410.0 pounds
89284

2006-07-16
#2 SRU incinerator (EPN #1-93)
#3 SRU incenerator
North Flare (EPN #20-72)
South Flare #20-72
Cause: Malfunction at the 450# bOiler Feed Water Discharge Check Valve leading to an automatics safety shutdown of SRU #2,3

Followup: No

Notes: SERC incident # 06-04451. Acid gas was routed to the flares and implimenting the refinery's Sulfur Shedding Plan
20,743.0 pounds
89284

2006-07-16
#2 SRU incinerator (EPN #1-93)
#3 SRU incenerator
North Flare (EPN #20-72)
South Flare #20-72
Cause: Malfunction at the 450# bOiler Feed Water Discharge Check Valve leading to an automatics safety shutdown of SRU #2,3

Followup: No

Notes: SERC incident # 06-04451. Acid gas was routed to the flares and implimenting the refinery's Sulfur Shedding Plan
571.0 pounds
89141

2006-07-10
North Flare (EPN #20-72) and #2 SRU incinerator
Cause: Sulfur condenser Level Control Valve malfunctioned and a 1st attempt at repair did not correct the problem (malfunction and human error). Operations were able to be continued manually but operator had to go to another unit and the #2 SRU tripped on low water level in the condenser.

Followup: No

Notes: SERC Incident # 06-04286. routed acid gas to the N. Flare to reduce env. Impact Valve of SRU was repaired that day. Disciplinary actions were conducted to deal w/ human error.
2,960.0 pounds
06-BB013-3752

2006-07-07
South Flare EPN #20-72
Cause: SRU malfunction--Loss of steam to the Main Air Blower turbine due to malfunction in the Platform and BOiler TB-01 resulting in an automatic safety shutdown.

Followup: Under Investigation

Notes: SERC incidentReport #06-04249. Has one inconstent calculation of 29, 175 of Sulfur Dioxide being released. (pg. 3)
14,765.0 pounds
89105

2006-07-07
North Flare (EPN #20-72)
Cause: safety shutdown of #2 SRU because of a malfunction at the TGT stripper reflux Accumulator Control Valve, which failed to open the N. Flare

Followup: No

Notes: SERC Incident # 06-04250. That unit had not reached stable operation levels since its startup on June 1, 2006 due to various mechanical malfunctions. Acid gas was routed to the flare until SRU was stabilized- to mitigate env. Impact.
29,175.0 pounds
89002

2006-07-01
North Flare (EPN #20-72)
Cause: Unintentional Trip of #2 SRU when console operator inadvertently entered an incorrect set point for the Main Air Valve Positioner.

Followup: No Information Provided

Notes: SERC Incident # 06-14134. Acid Gas was routed to the North Flare until #2 SRU was returned to service to cut down env. impact.
1,282.0 pounds
88939

2006-06-28
South Flare EPN #3-77
Cause: #3 SRU (Sulfur Recovery Unit) Bypass- Unintentional trip of the unit from a satellite monitoring location that was thought to have no active control. When SRU returned to service Sulfur Dioxide leaked from #3 TGT (Tail Gas Treater) until sufficient acid gas could sustain #3 TGT.

Followup: No

Notes: Plant followed operating procedures to mitigate the damage routing acid gas to the S. flare. Also, implimented sulfur shedding plan to reduce Sulfur Dioxide emissions. Brought the SRU online as soon as possible. Afterward, reconfigured DCS (Distributive Control System) to ensure that satellite monitoring screens had no active control capability.
29,813.0 pounds
100603

2007-10-30
Malfunction at the offsite vendor facility which provides hydrogen to Murphy. (Could this be Air Products - see incidents # 93737, 98860, 99344, 99713)
Cause: On 10/28/2007, MOUSA conducted an emergency shut down of the #3 SRU after being forces to shut down the Hydrocracker (its source of acid gas) following a malfunction at the office vendor facility which provides hydrogen to MOUSA. There was no malfunction or human error on the part of Murphy. On 10/30/2007, MOUSA stared the #3 SRU back up following the above mentioned shutdown

Followup: No Information Provided

Notes: This incident was not preventable because the shutdown of the hydrocracker and subsequent shutdown of the #3 SRU were the result of a malfunction at our offsite hydrogen vendor. BUT, the report says that yes, MOUSA could have attempted a startup without a bypass of the #3 TGT, but that MOUSA opted to use the safer TGT startup procedure of bypassing the TGT in order to better control Reactor Bed temperatures, which was more protective of personnel and equipment. The more aggressive startup optiif it had resulted in another exothermic reaction, could have damaged equipment and resulted in prolonged bypass of the #3 TGT, resulting in significantly greater sulfur dioxide emissions. Remedial Measures - MOUSA suspects that excess oxygen upset t
30.0 pounds
99828

2007-09-28
FLARE - the episode resulted from a valve misalignment involving the uncommanded closure of the SCOT inlet control valve, which triggered the unit's automatic Safety Instrumented Shutdown process. A root cause analysis concluded that a loose wir
Cause: the episode resulted from a valve misalignment involving the uncommanded closure of the SCOT inlet control valve, which triggered the unit's automatic Safety Instrumented Shutdown process. A root cause analysis concluded that a loose wire tripped the fuse supplying power to the valve solenoid

Followup: No Information Provided

Notes: This incident was not preventable because the loose wire occurred despite inspections made during routine maintenance and operator rounds. Remedial Measures - MOUSA is actively working to install redundant solenoids on this critical valve. SEE LDEQ reports # 99867, 9986
23,988.0 pounds
99713

2007-09-24
FLARE - Malfunction of Air Products Gas Oxygen Compressor / North Flare
Cause: a release to the North Flare in which process safety valve intermittently relieved pressure from the Area 6 Rich Amine Flash Drum. The unit was upset due to low hydrogen purity from Air Products due to a malfunction of their Gas/Oxygen Compressor.

Followup: No Information Provided

Notes: In Murphy's report, they acknowledges that the Area 6 Rich Amine Flash Drum has been involved in two recent events - 8/23 and 9/10 but that improved monitoring systems have enabled MOUSA to more accurately estimated emissions. NOTE - the LDEQ report, which was made my Murphy, states that a hydrogen supply problem to the refinery and an faulty flow meter (which was replaced) were the causes of the release
25.0 pounds
99344

2007-09-10
FLARE - Malfunction of Air Products Gas Oxygen (GOX) Compressor / South Flare
Cause: the incident was a result of light hydrocarbon contamination (methane) in the supply of pure hydrogen to MOUSA from Air Products resulting from a malfunction of their Gas Oxygen (GOX) Compressor. Hydrogen Purity abruptly dropped from 99.5% to approx. 95%. The methane flashed, exceeding the pressure setting on the relief valve from the Flash Drum to the Flare

Followup: Yes

Notes: This incident was not preventable because MOUSA was unable to predict the malfunction of the Air Products GOX compressor and was not provided timely notification of the problem. There was no malfunction or human error on the part of MOUSA. RemedialMeasures - In order to quickly detect and respond to such events, MOUSA gained access to the data from the Air Products online hydrogen purity analyzer on the supply line from Air Products. At the next unit turnaround, MOUSA will install a Rich Aminash Drum pressure indicator on the DCS console. MOUSA also developed an operating procedure to standardize the adjustments that must be made to quickly overcome such an event. The corrective actions listed above should enable MOUSA to provide timely
9,557.0 pounds
98860

2007-08-23
FLARE - Malfunction of Air Products Gas Oxygen (GOX) Compressor /South Flare
Cause: the incident was a result of light air hydrocarbon contamination in the supply of pure hydrogen to MOUSA from Air Products resulting from a malfunction of their Gas Oxygen (GOX) Compressor. The hydrocarbon impurities flashed, exceeding the pressure setting on the PSV from the Flash Drum to the Flar

Followup: Yes

Notes: This incident was not preventable because MOUSA was unable to predict the malfunction of the GOX compressor at the hydrogen vendor and was not provided timely notification of the problem. There was no malfunction or human error on the part of MOUSA. Remedial Measures - First, MOUSA worked with the Air Products to develop a communications system should they experience malfunctions in the future. Second, MOUSA developed an emergency procedure to react to such an event. Third, MOUSA developed impd monitoring of the flow rate off the PSV to more accurately estimate emissions from such an event. (Flow rate went off scale on the flow meter, so MOUSA re-ranged the meter. A similar event occurred on 9/24/2007 and data from that event suggested th
19,000.0 pounds
98709

2007-08-16
FLARE - #3 TGT Bypass
Cause: This shutdown and the subsequent release can be attributed to a process upset. The incident occurred as MOUSA was troubleshooting deviant values in the air demand ratio as part of an effort to proactively diagnose potential problems in the unit. As MOUSA took a flow indicator offline to examine it, the air-to-fuel ratio drifted off-specification, triggering a safety shutdown of the unit on loss of flame in the TGT feed heater

Followup: No Information Provided

Notes: There was a problem with the air demand ratio controller on the #3 Tail Gas Treater. While the company was troubleshooting the problem they placed the unit on manual control. The unit then proceeded to drift off of the settings and reached a condition where the unit took an automatic safety shutdown. The shutdown could probably have been averted if the ratio drift had been anticipated so this shutdown was due to an unanticipated process upset but the next time the ratio controller has a problem theany should be able to avert a shutdown by carefully monitoring the air demand ratio. - LDEQ report. This incident is listed as being preventable but the only information in that section is that MOUSA did not anticipate this event in the development o
1,031.0 pounds
98724

2007-08-16
DHT Sour Gas Compressor/ DHT Overhead Receinver
Cause: the incident was triggered by a faulty level reading in the DHT Overhead Receiver (reading 30% less than actual). The compressor shut down when the knockout pot downstream of the DHT Overhead Receiver alarmed on high liquid level. The level gauge apparently failed due to scale (rust) plugging the instrument.

Followup: No Information Provided

Notes: The incident is listed as preventable even though the only information included in that section is that MOUSA did not anticipate the accumulation of scale during the extended shutdown of the vessel. Remedial Measures - the DHT unit had been shut down for 110 days. MOUSA is working on plans to prevent scale formation by securing the Overhead Receiver under an inert atmosphere in any future extended shutdowns. Note: the flare resulted from an automatic safety shutdown of the DHT Sour Gas Compre - but nonetheless, the incident was triggered by a faulty level reading in the DHT Overhead Receiver - the level gauge having failed due to scale (rust) plugging the instrument.
261.0 pounds
98371

2007-08-01
FLARE - Relief Valve on the MDH High Pressure Stripper / South Flare
Cause: on 8/3/2007, MOUSA discovered that a pressure relief valve on the MDH High Pressure Stripper was opening to the South Flare on an intermittent basi

Followup: No Information Provided

Notes: This incident is listed as preventable even though the only information included in that section is that there were no mechanical failures or human error. MOUSA's report states that they suspect that ambient weather conditions (90 degrees, looping East wind at 0-5 mph) contributed to the episode, preventing typical dispersion of emissions to upper levels. Murphy received 3 citizen calls on 8/2/2007 for odor. They investigated each complaint and found transient odors consistent with trace ats of sulfur dioxide. They examined process conditions and found no upset conditions and no elevated levels of sulfur dioxide emissions from the facility - as noted by the numerous continuous emissions monitoring systems associated with heaters, boil
1,110.0 pounds
97825

2007-07-12
Thermal Reactor
Cause: MOUSA shut down the #2 SRU in order to inspect a visible leak in the Thermal Reactor. MOUSA found localized corrosion damage to the shell resulting from acid gas infiltrating a small defect in the refractory.

Followup: No Information Provided

Notes: This incident was not preventable because the leak in the Thermal Reactor was not a predictable event. Remedial Measures - MOUSA shut down the unit, conducted a thorough inspection, and patched the leak in accordance with API 510. MOUSA will repair the internal refractory during the next scheduled turnaround. MOUSA conducts routine on-stream ultrasonic inspections on this unit to monitor equipment fitness
113.0 pounds
96570

2007-05-29
High vibration trip in the HCU Recycle Gas Compressor
Cause: the startup of the #3 Sulfur Recovery Unit was a result of a shutdown of said unit which was the result of a lack of feed after an automatic safety shutdown of the Hydrocracker (high vibration trip in the HCU Recycle Gas Compressor). The vibration in the compressor was apparently due to surging in the unit during low flow conditions.

Followup: Yes

Notes: This incident was not preventable because the erratic performance was not a predictable event. Remedial Measures - MOUSA installed mechanical stops on the spillback valves to prevent erratic performance during low flow situations. MOUSA modified its startup procedure to eliminate the TGT Bypass.
789.0 pounds
96333

2007-05-18
#3 SRU Incinerator (#5-00) / South Flare (#3-77)
Cause: 5/18 shutdown of the #3 SRU which was the result of a lack of feed as MOUSA reduced feed to the hydrocracker and other units following a safety shutdown in the Crude Unit. MOUSA attempted to restart and line out units in the refinery and on 5/20 the #3 SRU unit shutdown after its source of acid gas, the Hydrocracker Unit, shutdown on 5/20 because of a malfunction at the Recycle Gas Compressor (high vibration) which triggered an automatic safety shutdown of the Hydrocracker. On 5/21 #3 SRU was started up and on 5/23 the #3 SRU experienced an automatic safety shutdown which was the result of a solenoid malfunction on the SCOT bypass valve (v-509), which failed to open while lining up the Tail Gas to the SCOT Reactor, per the startp plan. The # 3

Followup: Yes

Notes: Even in the final 10/18/2007 follow up report Murphy does not explain whether the incident was preventable or not. Remedial Measures - Regarding the HCU shutdown, MOUSA installed a new probe to monitor vibration in the HCU Recycle Gas Compressor. Regarding the # 3 SRU malfunction, MOUSA has (1) replaced the solenoid on TB-NV-509, (2) modified the unit startup procedure to limit the recirculating gas rates through the startup blower just before diversion of the SRU tail gas to the Absorber Secof the Tail Gas Unit, (3) developed a Preventative Maintenance schedule to conduct inspections on the exhaust screens on critical solenoids in the #3 SRU, and (4) installed new logic to improve the coordination of the two valve actuators. Note: all
15,688.0 pounds
94267

2007-02-28
FLARE - HCU Recycle Gas Compressor
Cause: during a startup event there was a release of sulfur dioxide. There was a shutdown of the #3 Sulfur Recovery Unit on 2/26/2007 due to a malfunction in the HCU Recycle Gas Compressor resulting from a faulty governor on the steam turbine lube oil pump. That caused the automatic safety shutdown of the Hydrocracker.

Followup: No Information Provided

Notes: This incident was not preventable because the failure of the governor was not predictable. Remedial Measures - While the governor is subject to the Preventative Maintenance program, the refinery will assemble a team to investigate possibilities fro improving the reliability of the compressor assembly
573.0 pounds
94158

2007-02-23
FLARE-Temperature Transmitter /
Cause: the startup followed a shutdown of the #3 SRU complex on 2/23/2007, after its source of acid gas, the Hydrocracker Unit, experienced an automatic safety shutdown . The shutdown was triggered by a high temp. indication on the HCU Makeup Gas Compressor. Atemp. transmitter failed due to damage to its insulation and a loose connection. In failing, the transmitter sent a false high temp. indication, which triggered the shutdown of the compresso

Followup: No Information Provided

Notes: This incident was not preventable because the failure of the wiring was not a predictable event. Additionally, the excess emissions are a normal part of the unit startup. Remedial Measures - MOUSA reprogrammed the transmitter to send a low temp. signal on failure, which will avoid a compressor shutdown. MOUSA activated the instrument's dual element technology, such that if one element fails, it will automatically switch to the backup. This will improve the reliability of the transmitter. Nthe shutdown was triggered by a high temp. indication on the HCU Makeup Gas Compressor A. A temp. transmitter failed due to damage to its insulation and a loose connection. In failing, the transmitter sent a false high temp. indication, which trigge
367.0 pounds
93737

2007-02-05
Air Products hydrogen plant
Cause: -The startup followed a shutdown of the # SRU complex on 1/28/2007, after its source of acid gas, the Hydrocracker unit, was shut down. The Hydrocracker unit, which is supplied by Air Products via pipeline. A malfunction of the Air Products hydrogen plant forced MOUSA to shut down the hydrocracker. This incident is a normal startup of a Sulfur Recovery Unit

Followup: No

Notes: This incident was not preventable because, excess emissions are a normal part of the unit startup. No human error was involved. Remedial Measures are listed as, the excess emissions are a normal part of the startup. The LDEQ incident report further explains that, The # 3 SRU was being brought on line. The process took about 6 hours. Murphy's written report to LDEQ incorrectly dated 1/12/2007 states that the startup followedhutdown of the #3 SRU complex on 1/28/2007, after a malfunction in at the Air Products Hydrogen Plant forced MOUSA to shut down the Hydrocracker
458.0 pounds
93741

2007-02-05
FLARE- Boiler feed water steam turbine pump
Cause: there was a trip in the boiler feed water steam turbine pump. The backup electric pump auto started as designed but before the water level in the boiler was back to normal, there was an event that released listed amount of S02 from the flare. This is considered to be a process upset

Followup: Yes

Notes: Verbal Report - There is no information as to whether this accident was preventable or not. There is no information regarding any remedial measures that have been taken in regards to this incident. Note: the LDEQ writes this concerning the flare, The flare does operate as designed and at times is noisy and smokey.
157.0 pounds
110526

2008-10-31
FLARE- Hydrocracker and #3 SRU Startup
Cause: No Information Given

Followup: Yes

Notes: This incident was under investigation as was the root cause on 11/7/2008 when Murphy notified LDEQ of said incident. There were no follow-up letters included for December 2008 in the information the Bucket Brigade received.
14,983.0 pounds
109794

2008-10-03
FLARE - #2 FCCU Wet Gas Compressor
Cause: No Information Given

Followup: Yes

Notes: Note that at the date of this report - 11/10/08, the incident was still under investigation and that includes a root cause analysis.
1,575.0 pounds
109460

2008-09-22
FLARE - Boiler Feed Water Pump B-P-022A
Cause: the event was apparently triggered by the loss of boiler feed water pump B-P-022A due to high bearing temperatures after loss of cooling water to the bearing housing. The lack of water was due to plugging (Zebra mussels) of the cooling water line. MOUSAhad the pump on a temporary cooling line (once-through cooling water from the Mississippi River) because the Area 6 Cooling Tower was shut down on 9/21 due to a planned maintenance turnaround of the Hydrocracker Unit.

Followup: Yes

Notes: This incident was not preventable because MOUSA could not anticipate that the temporary cooling line would plug. Remedial Measures - for future events when the Area 6 cooling tower is shut down, MOUSA will run B-P-022B on conditioned city water. Subsequent to this event, MOUSA installed connections to enable the use of a temporary cooling tower to supply high quality cooling water if the conditioned city water is unavailable.
8,842.0 pounds
108144

2008-08-19
FLARE - # 3 TGT Quench Tower Water Pump
Cause: the damage to the quench pump was a result of inadequate monitoring of the caustic addition system and the miscommunication that allowed the quench water pHto of off specification. MOUSA adjusts the pH if the circulating quench water by adding caustic to the loop. At the time of this incident, the caustic tote ran empty (the tote did not have any external level indication devices on it). Due to a miscommunication, MOUSA idd not refill the tote in a timely manner, leading to an 18-hour period of lowpH quench water that resulted in corrosion damage to the quench water pump

Followup: Yes

Notes: The final report from Murphy states that remedial measures include: In October, MOUSA replaced the TGT catalyst as part of a planned maintenance turnaround on the #3 SRU complex. MOUSA plans to install a second tote as a spare, and add sight glasses to both for quick verification of liquid levels. MOUSA will conduct preventative maintenance inspections on the quench water system. MOUSA will issue a Safety Alert to educate employees of this episode and its causes. NOTE: LDEQ investigations intoidents 108144 and 108122 both revealed control facilities not installed and/or properly maintained. The facility has been referred to the LDEQ Enforcement Divisio
1,700.0 pounds
108122

2008-08-16
FLARE - Boiler Feed Water System / #2 SRU Startup / Hydrocracker
Cause: corrosion damage in B-V-454 - the control systems did not allow B-V-453 and B-V-454 to run reliably in parallel, as the level controllers attempt to work independently operators were unaware that the north and south BFW systems were operating on a common BFW line because a seldom used valve was open. Operating procedures did not address the potential for imbalance in the system when B-P-006B was shut down. in order to overcome the aforementioned design flaw, operators run the level control bypass on B-V-454 on manual. MOUSA found that existing procedures did not address all potential failure events in this operational mode.

Followup: Yes

Notes: This was an incident that involved three separate incidents. It is listed as preventable because the Boiler Feed Water trip on 8/16/2008 was found to be the result of faulty design, equipment malfunction, and operator and procedural error. Emissions from the startup of the #2 SRU were part of the normal startup procedure. The hydrocracker trip on 08/20/2008 was found to be the result of operator and procedural error. REMEDIAL ACTIONS -MOUSA repaired the trays in deaerator B-V-454. They modified prores regarding boiler feed water pump operations and is investigating engineering changes to improve controls on the deaerators. Also, they are developing procedural updated regarding the startup of the Hydrocracker. They completed repairs on MUG Comp
13,897.0 pounds
103793

2008-03-10
FLARE- #2 Sour Water Stripper Malfunction / South Flare
Cause: faulty transducer on the control valve actuator

Followup: No Information Provided

Notes: This was a self report by Murphy. They verbally called in on 3/10/2008 and provided written notification on 3/17/2008. This is important because in their initial verbal report, the list sulfur dioxide, hydrogen sulfide, and volatile organic compounds ashaving been released. However, in their written report they only list sulfur dioxide as having been released. This accident was not preventable because the malfunction of the transducer was not a predictable event. Remedial Measures - MOUSA replaced faulty valve transducer with an upgraded, more robust model. MOUSA is identifying critical pressure control valves that have these particular trasducer models in order to determine which would benefit from upgraded transducers.
698.0 pounds
102685

2008-01-29
FLARE - #2 SRU Startup / plant instrument air
Cause: the episode was a result of a January 29th shutdown due to an emergency safety shutdown of the unit following a malfunction of plant instrument air.

Followup: No Information Provided

Notes: This incident was not preventable because these levels of emissions are consistent with out SSM Plan. Remedial Measures - regarding the #2 SRU startup, no Corrective Actions are warranted. Regarding the instrument air failure, please refer to correspondence related to SERC Incident Number 08-00537. (at this time we do not have a copy of this)
308.0 pounds
102619

2008-01-21
FLARE- pressure relief valves in the #2 SRU complex / North and South Flares
Cause: leaking pressure relief valves in the #2 SRU complex.

Followup: No Information Provided

Notes: This incident was not preventable because the PRV malfunctions were not predictable events, as recognized by NSPS for flares that exempt PRV leakage. Also, permitted emission rates at both the North and South flares are based on estimated provided by a refinery-wide survey. not on monitoring data. NOTE: In the report Murphy acknowledges the flow to the North Flare could not be reliably ascertained (no reason given why it couldn't be), the quantity can only be estimated. It was estimated that ave sulfur dioxide emissions from this incident were 200 pounds per hour at the North Flare. They claim that MOUSA is currently on the process of developing an advanced flow monitoring system for both flares. I cam up with the total amount of sulfur di
38,400.0 pounds
102451

2008-01-20
Instrument Air Compressor - #3 SRU Malfunction
Cause: the air register to the Incinerator failed closed, starving the Incinerator of combustion air and resulting in a flameout in the #3 SRU Incinerator. The air register malfunctioned due to ice formation in the instrument. (overnight temperatures in the area were below freezing). The root cause was moisture in the instrument air from an instrument air compressor.

Followup: No Information Provided

Notes: This incident was preventable because the instrument air line was not run through a drier, and MOUSA has no standard to address this issue. Remedial Measures - MOUSA published a standard that all instrument air from compressors must be run through driers.
102452

2008-01-19
FLARE - primary (north) Combustion Blower for the #2 SRU Thermal Reactor
Cause: the episode was the result of a January 15th shut down of the #2 SRU due to and emergency safety shutdown of the unit following a malfunction of the primary (north) Combustion Blower for the SRU Thermal Reactor. MOUSA started the backup (south) blower, but this machine exhibited high vibrations, so MOUSA was forced into a safety shutdown of the #2 SRU.

Followup: No Information Provided

Notes: This incident was not preventable because the blower malfunction was not a predictable event. Remedial Measures - MOUSA repaired the North blower and returned the unit to normal operation without further incident. MOUSA is considering a redesign of the blower system.
687.0 pounds
102027

2008-01-03
FLARE - #3 Sulfur Recovery Unit Incinerator stack (EPN: 5-00)
Cause: excess emissions of sulfur dioxide occurred at the #3 SRU Incinerator stack due to a malfunction of the #3 SRU. The malfunction, a flameout in the #3 SRU TGTU Tail Gas Burner, resulted in an automatic TGT bypass. The MCR (Master Control Relay) connections were checked because and analysis of the Triconex output indicated a probable loose connection. A loose connection was found and repaired.

Followup: No Information Provided

Notes: This was a self report to LDEQ with a follow-up report both from Murphy. The incident was not preventable because the loose connection was not a predictable human event. Remedial Measures - MOUSA inspected the unit and found a loose connection at the #48 terminal in the Master Control Relay for the #3 SRU. MOUSA tightened the connection and set up a Preventable Maintenance work order to inspect all critical relay connections during the next planned unit shutdown.
123.0 pounds
102011

2008-01-02
FLARE - Main Airblower at the #2 FCC, C3/C4 Splitter/ FCCU Fractionator
Cause: the refinery experienced an automatic safety shutdown of the Main Air Blower at the #2 FCC, resulting in the release of FCC catalyst from the #2 FCC ESP stack (EPN #2-77). As MOUSA attempted to start the unit and achieve balanced operations in the refinery, the C3/C4 Splitter experienced a malfunction, resulting in a large flame with smoke emissions at the North Flare. The events may have been related and are under investigation. (Maybe an air pocket got into the system and caused this -see #102043)

Followup: Yes

Notes: This incident report includes two citizen complaints and a self report from Murphy to the LDEQ. Incident #102043, 102007, 102011, and 102050 are all regarding the same incident as best I can tell. In Murphy's report, they acknowledged that the eventresulted in significant flaring from the FCC main column overhead receiver and the C3/C4 Splitter. Also, MOUSA claims that they received three complaints of visible emissions but no allegations of impact. The LDEQ report states that some particulateter was released to the neighborhood and that at the time of the incident there was a north/northwest wind. NOTE- at the time of this report the incident was under investigation. However, no follow-up report was provided to the Bucket Brigade.
40.0 pounds
120404

2009-12-23
North Flare from #2 SRU Incinerator
Cause: Automatic safety shutdown of #2 SRU occurred due to malfunction of the burner. This caused flaring at the North Flare.

Followup: No

Notes: RQ exceeded. Murphy Oil started procedures and re-started the unit. Root cause is under investigation.
3,090.0 pounds
119999

2009-12-09
North Flare from #2 SRU Incinerator
Cause: Automatic safety shutdown of #2 SRU due to malfunction in the SRU main burner flame dectors. Caused flaring from the North flare.

Followup: No

Notes: RQ exceeded. Refinery followed operating procedures. Unit was re-started and Root Cause Analysis is on-going.
10,800.0 pounds
118251

2009-09-27
#2 SRU incinerator
Cause: Automatic safety shutdown of #2 Sulfur Recovery Unit due to hydrocarbon breakthrough into the unit. Attempted to re-start the unit because had to bypass acid gas around #2 Tail Gas Treater which resulted in emissions. A second attempt to start up was successful but also required a bypass which results in further emissions.

Followup: No

Notes: RQ not exceeded. Gas bypasses were secured in both cases. Refinery followed propr procedures and appropriate repairs will be done on the unit.
159.0 pounds
115235

2009-05-24
North flare from hydrocraker
Cause: Automatic safety shutdown of the hydrocracker unit. Cause flaring at North flare.

Followup: No

Notes: RQ exceeded. Secured and re-started hydrocracker.
4,000.0 pounds
112823

2009-02-18
North Flare
Cause: Automatic safety shutdown of hydrocracker unit resulted in a North flare with no smoke.

Followup: No

Notes: RQ exceeded. Re-started the hydrocracker according to procedure.
4,000.0 pounds
112011

2009-01-13
#3 SRU Incinerator
Cause: The flame on #3 SRU Incinerator's burner went out.

Followup: No

Notes: RQ not exceeded. Burner was re-lit to resume normal operations. Cause is under investigation.
215.0 pounds
111906

2009-01-09
South Flare
Cause: Power interruption to units. Shut down units due to the safety procedures that caused smoke to be released at South Flare.

Followup: No

Notes: RQ not exceeded. Followed operations to secure and re-start the units.Sulfur Recovery Units remained online throughout.Power interruption cause is under investigation.
235.0 pounds
127860

2010-11-22
FLARE: #2 SRU [#1-93]; North Flare [EPN 20-72]
Cause: Refinery letter indicates that facility flared sulfur dioxide from the North Flare due to the shutdown of the #2 SRU. Emissions were also released from the incinerator stack. A root cause analysis will be conducted to determine the trigger for the shutdown. FOLLOW-UP: Level indicator failed at #1 SWS Overhead Receiver and #1 SWS Off-Gas knockout Pot (SA-V-102). This caused erratic flame at SRU furnace ultimately causing safety shutdown. Root cause was formation of ammonia salts plugging the level indicators; this was "the result of insulation and steam tracing on these level indicators that did not conform to design conditions. Some insulation was not in place and some steam tracing was not in contact with the process piping." DEFERRED MAINTENANCE.

Followup: No

Notes: RQ. Shut down unit and steamed out level indicators. Restored the insulation and steam tracing on the level indicators to design conditions.
1,391.0 pounds
126996

2010-10-09
FLARE - North Flare (EPN:20-72)
Cause: A pressure relief valve opened at #2 Hijet system due to a malfunction in the #2 Hijet where a line was plugged with ammonia salts. This lead to SO2 emissions at the North Flare (EPN:20-72). FLARE.

Followup: Yes

Notes: RQ. Reportable quantities for sulfur dioxide were exceeded. Immediately the line was cleaned and #2 Hijet was restored to normal operations. A pressure transmitter was installed on the affected line to provide early detection of accumulated ammonia salts. An injection point was installed to allow flushing of the line with hot boiler feed water.
13,380.0 pounds
126739

2010-09-28
FLARE - North Flare (#20-72)
FLARE - South Flare (#3-77)
Cause: Power Outage. A power interruption caused emergency safety shutdowns in several units. The hydrocracker shut down, and hydrogen from it was combusted at the North Flare. At the South Flare a mix of hydrocarbon vapors were combusted. There were brief, intermittent periods of flaring. FLARE. FOLLOW-UP Letter states that the cause of the unanticipated power outage was a "failed lightening arrestor on a main feeder line."

Followup: Yes

Notes: BRQ. Follow-up letter states that release was below reportable quantities. Operating procedures were followed to safely secure and re-start affected units and they are investigating what caused the unplanned power interruption. Murphy Oil inspected all arrestors and replaced two that show signs of wear.
126739

2010-09-28
FLARE - North Flare (#20-72)
FLARE - South Flare (#3-77)
Cause: Power Outage. A power interruption caused emergency safety shutdowns in several units. The hydrocracker shut down, and hydrogen from it was combusted at the North Flare. At the South Flare a mix of hydrocarbon vapors were combusted. There were brief, intermittent periods of flaring. FLARE. FOLLOW-UP Letter states that the cause of the unanticipated power outage was a "failed lightening arrestor on a main feeder line."

Followup: Yes

Notes: BRQ. Follow-up letter states that release was below reportable quantities. Operating procedures were followed to safely secure and re-start affected units and they are investigating what caused the unplanned power interruption. Murphy Oil inspected all arrestors and replaced two that show signs of wear.
122144

2010-03-13
FLARE: North Flare (#1 Sour Water Stripper Flash Drum)
Cause: Refinery letter states that flaring of the #1 Sour Water Stripper Flash Drum occurred due to high pressure. The high pressure was caused by a faulty electrical breaker.

Followup: No

Notes: Murphy Oil followed its operating procedures to restore the #1 Hi-Jet to normal operation. LDEQ closed this incident case on 5/9/2011.
15.0 pounds
120544

2010-01-05
FLARE - South Flare (EPN #3-77)
Cause: Pressure increase in sulfur plant due to series of unit shutdowns, automatic safety diversion of naphtha vapors, pressure relief valve opened, released via South Flare. Letter states that "the pressure increase was apparently due to naptha vapors venting into the vessel during shutdown of the Hydrocracker Unit for a month-long refinery-wide maintenance turnaround." FLARE.

Followup: No

Notes: BRQ. Refinery letter states that "reportable quantity of a regulated material was not exceeded." Followed operating procedures in "Startup, Shutdown, and Malfunction Plan." Reviewing event to see if procedures need to be updated. Refinery letter only. No LDEQ report.
12.0 pounds
135917

2011-12-14
#3 SRU Incinerator stack
Cause: On December 14th Valero experienced excess emissions of sulfur dioxide and hydrogen sulfide at the #3 SRU Incinerator (EPN #5-00) due to automatic safety shutdown of the #3 SRU. Varying rates of emissions were released at the #3 SRU Incinerator stack while the #3 Tail Gas Treater (TGT) was bypassed as Valero worked to restart the unit.

Followup: No

Notes: Valero immediately enacted its Sulfur Shredding Plan to reduce the amount of acid gas routed to the unit, thereby reducing the emissions to the incinerator. The wind was from the NE at 5-10 mph during the incident. No allegations of impact were received from neighbors in the surrounding community. The episode occurred from approximately 12:45 pm until 6:40 pm on 12/14/11 and from 9:00 pm until 6:20 am on 12/15/11. Valero followed its operating procedures as described in MACT UUU Startup, Shutdown and Malfunction Plan in securing and restarting the unit.
3,100.0 pounds
135648

2011-12-03
No Information Given
Cause: Multiple issues involving the Flue Gas Cooler and Cat Cracker throughout the week caused periodic flaring, which resulted in noise, smoke, and odors. Noise Cause: The flue gas cooler on the Cat Cracker began experiencing an increase in pressure drop across its super heater section during the last week of November. It is believed that this increased pressure drop across the super heater section has resulted in deposits of salts in the super heater tubes and resulted in an increase in the operating pressure in the steam drum causing the excess noise. The pressure relief valves on the steam drum have vented periodically to protect the steam drum and maintain safe operation. The relief valve events are the source of the recent noise complaints. Flaring: the Cat Cracker wet gas compressor tripped off line resulting in a total shutdown of the Cat Cracker and flaring. A malfunction in the speed controls on the compressor is suspected as a cause.

Followup:

Notes: LDEQ received seven complaints regarding smoke, odors, noice, and vibrations from the Valero Mereaux Refinery. No RQ's were exceeded, but some permit limits were exceeded and will therefore be reported on the semiannual deviation reports. Corrective actions were implemented to prevent similar issues. Complaint reports included: 12/2 smells emanating from Meraux refinery caused headache, smells like burning fuel. South flare in use with deep, dark orange colors and trailing black smoke. The refinery noise has been in the home for the last few nights. 12/3 a constant high pitched tone in the house, large flame from both flare with smoke. 12/4 very strong possibly sulfur odor infiltrated home and can not be removed, so bad that it is making us nauseous, the odors have never been to this degree within our residence. 12/4 smell is stronger as approach refinery. It is a burnt gas smell. Very nasty around Ventura and further east, closer to refinery. 12/4 very loud medium to high pitched constant humming emanating from the valero Meraux refinery, can be heard in home over sound from television. 12/5 Rotten egg odors have been increasing over the last 2-3 days. 12/5 report of an odor of sulfur dioxide coming from a plant making resident sick. 12/9 extremely loud steam release this morning for about four minutes. Noise Corrective Actions: Cat Cracker operating conditions have been adjusted in an effort to reduce the steam make from the flue gas cooler. These actions include reducing Cat Cracker charge rate and adjusting unit operations to minimize regenerator temperature. The operating pressure has been lowered on a portion of the refinery steam system to minimize steam drum pressure on the flue gas cooler. Modifications were made to the system to allow steam condensate to be injected upstream of the super heater section in an effort to rid salt deposits. A super heater bypass line was designed and installed.
144600

2012-11-11
discharge piping of #2 HiJet
discharge piping of #2 HiJet and North Flare
North Flare
Cause: Valero experienced excess emissions of hydrocarbon vapors and H2S from a pin-hole leak on the discharge piping of the #2HiJet. The #2 HiJet collects low pressure sour gas from several units in the refinery, compresses it, and routes it to amine treatment for use in the refinery fuel gas system. In the final written notification dated March 11, 2013, Valero determined the root cause to be inadequate system design for corrosion prevention. The leak was caused by pitting corrosion on a piping elbow that was installed in 2010. This short service life indicates an aggressive corrosion mechanism that was not originally anticipated by Valero. Valero conducted ultrasonic and radiography surveys of this line and discovered lower than expected wall thickness in some areas and debris or sludge building obstructing flow in several locations. Low points allowing moisture and solids buildup can cause areas of aggressive corrosion in wet, hydrogen sulfide service. Valero also believes that the pipe metallurgy in this case, carbon steel, should be re-evaluated for fitness for service under these particular process conditions.

Followup: Yes

Notes: Valero quickly diverted the gases normally collected by the #2 HiJet to the flare and shut down the #2 HiJet. Valero then reduced charge rates of the affected units to minimize SO2 emissions at the flare and began the process of transferring some of the diverted gases to the #1 HiJet for recovery. The #1 HiJet has a lower capacity than the #2 HiJet and cannot take all the gases collected by the #2 HiJet. The Vacuum Unit Hotwell Offgas remained in the flare and lean amine to the Hotwell Offgas Scrubber was maximized to reduce SO2 emissions at the flare. Valero discovered that the valve separating the leaking pip and the #1 Amine Low Pressure Knock Out Pot was leaking by and sour gas continued to leak to the atmosphere. Valero installed a temporary hose upstream of the leak to allow the leaking section of the piping to be pressurized with Nitrogen and swept to the flare from a point downstream of the leak. Within minutes of starting the Nitrogen sweep, H2S was no longer detected in the area and the Total Sulfure Analyzer on the flare indicated a significant increase in the flare line. This caused SO2 emissions at the North Flare to exceed RQ. Valero installed a clamp on the leaking section of the pipe and restarted the #2 HiJet Valero issued a second and final follow up report to this incident on March 11, 2013 in which Valero determines the root cause of the release to be inadequate system design for corrosion prevention and believes pipe metallurgy should be re-evaluated.
861.0 pounds
143178

2012-09-23
North Flare
Cause: Units were in a start up after a leak on a refinery fuel gas line required a shutdown.

Followup: No

Notes: According to the notification report submitted by the facility, the facility reported a release from the fuel gas system. The fuel gas leak did not release a reportable quantity of flammable gas, however sections of the fuel gas system had to be isolated to perform repairs. Valero completed the start up of the Reformer and NHT according to procedure. Fuel gas leak happened 9/22/12. Sulfur dioxide release during Reformer/NHT startup happened 9/23/12.
788.0 pounds
143176

2012-09-23
North Flare
Cause: Valero reported excess emissions of sulfur dioxide and hydrogen sulfide at the North Flare during a start up of the Reformer unit. Valero continuously measures SO2 and H2S emissions at the North Flare. After 15 hours of Hydrogen flaring, the indicated sulfure content began to rise in an erratic, saw-toothed trend that was inconsistent with process conditions. Routine grad sample monitoring of this Hydrogen confirmed it to be essentially sulfur free. Within 1 hour of the end of Hydrogen flaring, the Total Sulfur readings returned to normal and the erratic saw-toothed trend stopped. Valero has evaluated the plant conditions and data recorded during this event and has concluded that the indicated Total Sulfure concentration was in error for the last 7 hours of flaring. Valero does not know what caused the erroneous readings, but the erratic, saw-toothed pattern trend was similar to previous episodes when the sample lines have become plugged with liquids. Valero will continue to investigate this event and work to identify and correct the cause of the erroneous readings.

Followup: No

Notes: 40 pounds of sulfur dioxide and less than 1 pound of hydrogen sulfide were released at the North Flare. Valero will work with the manufacturer to determine the cause of the Total Sulfur Analyzer malfunction and any possible corrective actions.
40.0 pounds
143223

2012-09-03

North Flare
Cause: Incident occurred following Hurricane Isaac at the North Flare during start up of the Hydrocracker unit. Valero has determined the cause to be the system design of the Hydrocracker/Hydrotreater Unit. Under normal operations, gases produced in the Hydrocracking/Hydrotreating Reactors, including H2S, are completely stripped out by steam in the Ore-Fractionator Stripper and sent to amine contractors for treatment; they do not pass into the Fractionator and on to the Fractionator Overheard Receiver. Consequently, the Fractionator Overhead Receiver was not designed with gas handling capabilities. Manual venting to the flare is the only available method of controlling an increase in pressure caused by gas carryover from the Pre-Fractionator Stripper. The design deficiency becomes apparent during unit start up because gases are produced prior to the ability to introduce stripping steam to the Pre-Fractionator Stripper. Stripping steam cannot be introduced until the unit is at the proper operating temperature. Operational experience has shown that even once stripping steam can be introduced, its use is limited at the low charge rates during a start up because excess steam causes erratic flows in the heater passes and delays the completion of the start up. A contributing factor in this event was that De-Asphalted Oil (DAO), a higher sulfur content feed, was introduced to the Hydrotreater prior to reaching adequate stripping steam rates in the Pre-Fractionator Stripper.

Followup: Yes

Notes: Valero will engineer and install a "start-up vent" that will direct the gases vented from the Fractionator Overhead Receiver to be collected by the refinery's HiJet, treated for H2S removal, and used in the refinery fuel gas system. Valero will also revise the Hydrocracker/Hydrotreater startup procedure to delay the introduction of DAO into the Hydrotreater feed until adequate stripping steam rates have been established. According to the LDEQ's list of reportable quantities, the reportable quantity for sulfur dioxide is 500 pounds.
1,102.0 pounds
142072

2012-08-14
#2 SRU Incineration and Boilers B-5, B-6, B-7, and TB-01
Cause: Excess emissions of sulfur dioxide at the #2 Sulfure Recovery Unity Incinerator Stack and Boilers due to the shutdown and subsequent startup of the #2 SRU and #2 Tall Gas Treater. They were shut down due to high pressure in the #2 SRU Furnace caused by plugging in the Sulfur Condenser Seal Legs. Valero has determined the root causes to be the operation of the #2 SRU with minimal acid gas feed to the unit and a steam leak into the process from a steam jacketed pipe between the Sulfur Condensor and the #4 Seal Leg. Past experience has shown that steam leaks into this system can form a mixture with sulfur and other contaminants present that can cause plugging. The reduced sulfur rate meant that there was less flow of sulfur to clear out any plugging that was forming. A corroded pipe cause the steam leak.

Followup: Yes

Notes: After a fire in the Crude Unit, the #2 SRU and many of the units that send acid gas to the #2 SRU were shutdown. To manage a building sour water inventory, Valero started up the #2 SRU with very little acid gas feed. Normally, the feed to the #2 SRU is a combination of acid gas and sour water stripper off gas with the higher proportion being acid gas. After the fire in the Crude Unit, the feed composition changed to a much higher proportion of sour water off gas. Sour water off gas contains less sulfur and more contaminants (e.g hydrocarbons and ammonia) than acid gas. Valero replaced the section of corroded pipe that caused the steam leak prior to the start up on 8/16/12. Valero will also replace all the steam jacketed piping in the #2 SRU at the next turnaround. Valero has commissioned a new acid gas transfer line from the #3 SRU that allows greater flexibility in supplying acid gas to the SRUs which will help prevent running either SRU at low gas rates. Valero will also revise the SRU operating procedures to ensure that this transfer line is used to maintain adequate gas flow. Sulfur dioxide released exceeds the reportable quanitiy of 500 pounds.
1,040.0 pounds
141477

2012-07-22
Crude Unit Fire
North Flare, South Flare, #2 SRU Incinerator Stack, Vacuum Tower Bottoms
North Flare, South Flare, #2 SRU Incinterator Stack; Vaccuum Tower Bottoms
Cause: Valero experienced a fire in the Crude Unit. Valero reported excess emissions of sulfur dioxide, hydrogen sulfide, and particulate matter from the fire, flaring at the North Flare and South Flare and excess emissions at the #2 Sulfur Recovery Unit (SRU) Incinerator Stack. Valero was in the process of starting up the Crude Unit following an electrical transformer failure which occurred in the Vacuum Unit on July 20. Incident number 141430 associated with the power failure describes details about the power failure and emissions released directly related to the event on that date. An 8 inch piping elbow in the Crude Unit failed, releasing Vacuum Tower Bottoms (VTB) onto adjacent piping and equipment. The hot product ignited, creating a fire in the pipe rack and a pool fure beneath the Crude Unit desalters and several nearby heat exchangers. The crude unit fire began at 0130 hours on July 22, 2013. The fire was "contained" at 0330 hours, and was extinguished at 0650 hours. The total time duration of the fire was 5.4 hours. The total flaring duration lasted 40.5 hours. Valero concluded that the triggering event was the failure of a piping elbow which resulted from a thinned wall due to high-temperature sulfidation corrosion. The elbow was of carbon steal construction, in a service requiring chrome alloy construction. Valero concluded that the root cause was that poor quality control practices and procedures were utilized when the elbow was installed in 1990 by the previous owner of the refinery.

Followup: Yes

Notes: Shutdown procedures were quickly initiated for all refinery units while the Valero Emergency Response Team responded to the fire. During the event and for part of the day, periodic flaring occurred as units were placed in safe condition. The fire lasted for a duration of 5 hours 24 minutes. Flaring associated with the refinery shutdown occurred for a duration of 40 hours 30 minutes. Sulfur dioxide, estimated at 2534 pounds, and hydrogen sulfide, estimated at 27 pounds, was released at the North Flare, South Flare, and the #2 SRU Incinerator Stack. Sulfur dioxide, estimated at 3382 pounds, and hydrogen sulfide, estimated at 5 pounds, was released from the uncontrolled burning of Vacuum Tower Bottoms in the fire. Before Completion of the repairs and startup of the Crude Unit, Valero conducted PMI testing of all piping circuits potentially subject to sulfidation corrosion in the Crude and Vacuum Units. During this process, some pipin and one additional carbon steel elbow were discovered and replaced. Valero will increase the inspection frequency from once every ten years to once every 2-3 years, which is more frequent than the 5-year inspection interval specified by industry standards for Class 1 piping.
5,916.0 pounds
141430

2012-07-20
North Flare, South Flare, and #2 SRU Incinerator Stack
Cause: Valero experienced excess emissions of SO2 and H2S at the North Flare, South Flare, and #2 Sulfur Recovery Unit (SRU) Incinerator Stack due to a sudden electrical transformer failure that cut power to several process areas within the refinery. Valero determined the root cause to be an electrical failure caused by water intrusion into the air terminal chamber on the 13.8 KV side of the transformer and inadequate insulation on the bus bar and connections. It appears that when the transformer was installed the 13.8KV incoming cables were too short to reach the transformer bushing so a field designed buss work and air terminal chamber was used. This locally designed air terminal chamber proved inadequate to protect the transformer breaker were improperly set and allow too much current to flow to the fault which caused voltage to sag across the reinfery and unnecessary tripped loads that upset other units.

Followup: Yes

Notes: The refinery initiated shutdown procedures for all affected units and followed the MACT UUU SSM Plan to recover the #2 Sulfur Recovery Unit (SRU) and #2 Tail Gas Treater (TGT). The #2 TGT was bypassed during the upset and subsequent startup. All refinery transformers were visually inspected for signs of water intrusion. Water was found in one other transformer of the same design which was removed and the air terminal box was sealed. The damaged transformer was replaced and a new overhead cable was used to replace the underground cable that was too short. Relay trip settings were changed to better coordinate and protect equipment and prevent unnecessarily upsetting other units. Valero has initiated a project to design and install appropriate terminal boxes in place of the locally designed ores for the three remaining transformers of the same design on site. According to the LDEQ's list of reportable quantities, the reportable quantity for SO2 is 500 pounds.
1,839.0 pounds
139318

2012-05-02
North Flare, South Flare, #2 SRU Incinerator, #3 SRU Incinerator
Cause: A lightning strike affecting Entergy's power distribution network caused a power interruption at the refinery, causing units to undergo safety shutdowns that included venting high rates of gases to both flares. The power interruption affected a significant portion of St. Bernard Parish.affected the north and south flare.

Followup: No

Notes: Power to the refinery was quickly restored, but the interruption tripped several units. The refinery established emergency procedures for the units. After stabilizing unit and refinery-wide conditions, the refinery methodically restarted each unit. The refinery received one citizen phone call for noise on the evening of the event. Reportable Quantity was only exceed for sulfur dioxide during this event, but the refinery will report emissions from this event for other pollutants in the annual Emissions Inventory.
2,364.0 pounds
138647

2012-04-10
North Flare & South Flare
North Flare, South Flare, #2 SRU Incinerator, #3 SRU Incinerator
Cause: The root cause of the event was found to be equipment failure at the Entergy substation adjacent to the refinery. Due to a total power interruption at the refinery, units underwent safety shutdowns, which included venting high rates of gases to the North Flare and the South Flare. There were periods of excess opacity at both flares, as there was no controlling steam available. The boilers were also affected by the power outage. As startups proceeded, the refinery experienced some noise from relief valves and some additional sulfur dioxide emissions at the North Flare. Entergy reported that the power interruption was caused by a severe electrical fault at a 13.8 kV tie breaker at the Meraux Substation. Entergy found no evidence to support a definitive root cause. There was some evidence of bird nesting in the immediate area of the fault.

Followup: Yes

Notes: The refinery shut down all units, per written procedures. Once power was restored to the refiner, the refinery assessed and methodically restarted each unit. The refinery received one citizen complaint for odor during this event.
15,199.0 pounds
138540

2012-04-03
North Flare
Cause: An unplanned shutdown and subsequent startup of the Hydrocracker Unit (HCU) occurred. The HCU charge pump tripped after its lube oil pump failed. Possible causes offered by Valero, as of 06/15/12, include a lightning strike and an equipment malfunction. The cause is under investigation at this point, and the refinery promised a follow up letter with the results of the investigation.

Followup: Yes

Notes: Per written procedures, the refinery shut down and started up the Hydrocracker Unit.
4,500.0 pounds
138274

2012-03-24
South flare
Cause: Above normal flaring occurred when the naphtha reformer experience an unplanned shutdown. Adjustments were being made to change operating conditions and the unit tripped.

Followup: No

Notes: Recycle gas was vented to the South flare until unit conditions were stabilized. The unit was immediately restarted. No significant sulfur dioxide emissions from the flare due to this event. Large dark orange flare with a much black smoke was seen.
137051

2012-02-07
North Flare
Cause: The emissions occurred during startup of the Hydrocracker Unit after a planned maintenance turnaround. The exact cause is under investigation, as of 02/14/12.

Followup: No

Notes: The refinery made some pressure adjustments in the unit to reduce the emission rate at the flare, and then the startup was completed. The incident is under investigation, which will result in a plan to prevent recurrence.
3,000.0 pounds
150231

2013-08-08
#2 SRU
Cause: Valero experienced excess emissions of SO2 and H2S at the #2 Sulfur Recovery Unit (SRU) and several refinery fuel gas-fired sources due to an unexpected shutdown at the #2 SRU. Valero Maintenance personnel were in a satelite equipment building to replace a cooling fan on the Uninterruptable Power Supply (UPS). When an electrician opened the cabinet to identify the cooling fan, the UPS shut down and power was lost to several key fueling-gas valves on the #2 Sulfur Recovery Unit (SRU). The valves moved to their fail safe position (shut) and the #2 SRU shutdown.

Followup: No

Notes: The electrician manually restored power to the #2 SRU fuel gas valves via the manual bypass switch on the UPS. After the Shutdown of the #2 SRU, Valero cut stripping to the #1 Ademine Unit to prevent acid gas flaring. This eventually resulted in increased Sulfur Dioxide emissions from heaters due to elevated hydrogen sulfide in the fuel gas system. The static switch control card was replaced and the UPS was returned to service approximately two hours after it had failed. Valero will also evaluate the following actions to further decrease the likelihood of re occurrence: 1) Replacing the UPS with a newer, more reliable model, 2) Changing out the 120 VAC fuel gas valves to 24 VDC valves that are then powered by the more reliable Distributed Control System (DCS) power supplies. Performing a test of the DCS power supply.
5,779.0 pounds
149430

2013-06-29

Cause: On June 29, 2013, the sulfur analyzer started reading heightened amount of SO2 releasing although all sources indicate normal SO2 levels, no units were in upset, and no flames were at flare.

Followup: No

Notes: Rescinded notification made for SERC incident #13-02879 on 6/29/13. The initial notification was made based on erroneous data provided by malfunctioning analyzer. No RQs exceeded. Analyzer has been fixed. Facility would like to rescind the notification made on 6/29/13.
149379

2013-06-12
KOH Treater Pressure Safety Valve, Benzene Reduction Unit
Cause: Liquefied Petroleum Gas (LPG)was being transferred to a crude KOH treater from a pressure vessel. The resulting pressure increase at the KOH Treater caused a pressure safety valve (PSV) to open and the LPG was directed to the north flare. The flow of LPG to the flare caused a larger than normal flare to occur, whether or not the PSV should have opened is still under investigation. During this same period and into 6/13/13 the Benzene Reduction Unit (BRU) was re-starting after being shut down for several weeks. The process also supplied gas to the north flare.

Followup: No

Notes: Investigation prompted by citizen complaint.
148798

2013-05-17
North Flare, #2 and #3 SRU, Heaters, Reboilers
Cause: On May 17, 2013 at approximately 15:43, Valero experienced excess emissions of Sulfur Dioxide at the North Flare, the #2 and #3 Sulfur Recovery Units, and several refinery fuel gas-fired sources due to an unexpected shutdown of the #3 SRU. The #3 SRU shut down on high burner pressure caused by a plugged condenser seal leg. After several unsuccessful attempts to unplug and restart the #3 SRU, Valero determined that the unit could not be restarted and completely shut down the unit. The Gas-Oil Hydrocracker/Hydrotreater was also shut down and refinery charge rates were reduced accordingly. Valero opened up the unit for inspection and discovered that catalyst from one of the reactor beds had migrated into the condenser and caused the plugging in the seal legs. Valero could not definitively identify the exact cause of the catalyst migration, but believes that it was most likely due to improper catalyst loading during the last catalyst replacement in 2010.

Followup: Yes

Notes: Valero immediately initiated its sulfur shedding procedure and attempted to unplug the #3 SRU condenser and restart the #3 SRU. Valero transferred as much of the remaining sulfur load to the #2 SRU as the unit's capacity would allow. Before the sulfur shedding procedure reduced the sulfur load to within the capacity of the #2 SRU, hydrogen sulfide entered the refinery fuel gas system and was combusted to sulfur dioxide in the refinery heaters and boilers. Hydrogen sulfide concentrations in the refinery fuel gas system returned to less than the 162 ppm NSPS Subpart J limit at approximately 05:14 on May 18, 2013. To prevent recurrence, Valero reloaded the #3 SRU with new catalyst and ensured that the catalyst was properly loaded and supported with additional support media. Valero plans to install a smaller mesh screen on top of the existing quarter inch screen that currently supports the catalyst bed and support media.
2,708.0 pounds
148704

2013-05-12

Cause: On May 12, 2013, the net gas compressor was shut down due to a control valve malfunction. The shutdown caused a release of sulfur dioxide to the flare.

Followup:

Notes: Maintenance was called to repair valve. Site was secured at 1600 hours on May 12, 2013. A separate ongoing event, SERC incident #13-01918, continued before, during, and after the Net Gas Compressor shutdown. An incident report for #13-01918 was submitted on 5/10/13. LABB cannot locate the incident report for the aforementioned SERC number.
230.0 pounds
No LDEQ Reported

2013-05-03
North Flare
Cause: On May 3, 2013 starting at approximately 02;00, Valero experienced excess emissions of Sulfur Dioxide and Hydrogen Sulfide at the North Flare during startup of the Gas Oil Hydrocracker/Hydrotreater Unit (HCU) following a planned maintenance outage and catalyst replacement. Because the catalyst was new, this particular startup include a procedure for sulfiding the catalyst prior to resuming normal operations. Sulfiding consists of circulating the feed in the reactors with an additive chemical to produce H2S, which is then maintained at a high concentration in the Recycle Gas for a period of time to allow the sulfides to deposit on the catalyst. Based on an initial assessment of the available data, excess emissions during the HCU startup are associated with the following: 1. The pressure safety valve (PSV) on the fractionator tower opened to flare. 2. The PSV on the Cold Separator was found to be leaking by the flare. 3. The Recycle Gas Compressor tripped and activated an automatic unit depressurization to flare. 4. The PSV on the Cold Separator opened to the flare. 5. The PSV on the Fractionator Tower opened to flare a second time. This incident is currently under investigation and Valero will submit additional information upon completion.

Followup: No

Notes: While the PDF of the attached document bears the LDEQ # 147895, this number is also linked to an incident of a different date (April 5, 2013). Valero reduced pressure to reseat PSV's that had lifted and attempted to stop the leakage on the Cold Separator PSV. Sulfur dioxide estimated at 3131 pounds and hydrogen sulfide estimated at 34 pounds were released during the "start up period" 5/3 02:00 to 5/4/13 22:00. Sulfur dioxide emissions associated with the leaking Cold Separator PSV have continued at approximately 20-30 pounds/hour. As of 08:00 on 5/10/13, an additional 3932 pounds of sulfur dioxide and 43 pounds of hydrogen sulfide are estimated to have been released.
7,063.0 pounds
148510

2013-05-03
Cold Separator PSV in the Gas Oil Hydrocracker/Hydrotreater Unit
Cause: On May 3rd 2013, starting at approximately 2:00, Valero experienced excess emissions of sulfur dioxide and Hydrogen Sulfide at the north flare during startup of the gas oil Hyrdocracker/ Hrydrotreater Unit (HCU) following a planned maintenance outage and catalyst replacement. Excess emissions during the HCU startup were associated with the following events: 1. The Pressure Safety Valve (PSV) on the Fractionator Tower opened to the flare 2. The PSV on the cold seperator was found to be opened to the flare 3. The Recycle Gas Compressor (RGC) tripped and activated an automatic unit depressurization to the flare. 4. The PSV on the Cold Seperator Opened to the Flare 5. The PSV on the Fractionator Tower opened to the flare a second time Valero determined the root cause of the PSV actuations to be inadequate startup procedure. Valero determined the root cause of the RGC trip to be an instrument technician lifting the instrument wires for a thermocouple that provided a shutdown interlock. Contributing factors to this root cause were: 1. Neither the operator nor the instrument technician was aware that this thermocouple provided a shutdown interlock 2. The instrument technician did not reference any documentation to verify that this transmitter was a possible Safety Critical Instrument 3. The reference documentation was inadequate 4. The instrument was not labeled in the field as a Safety Critical Instrument contrary to Valero standard procedure 7/2/2013 report states that written notification was submitted on 5/10/2013. This documentation is not available on the LDEQ document database.

Followup: Yes

Notes: Valero reduced pressure to reseat PSVs that had lifted and attempted to stop the leakage on the Cold Separator PSV. Valero shut down the HCU on 5/13/13 and replaced the Cold Separator PSV. Valero will revise HCU startup procedure to include a maximum charge rate limit and maximum Cold Separator pressure limit during sulfiding and also to ensure that the Cold Separator pressure control valve is initially lined up for feed introduction into the unit. Valero repaired the thermocouple and corrected the documentation to reflect that it is a Safety Critical Instrument. Valero has also labeled this instrument in the field. Valero will also finalize a Safety Critical Instrument List in the HCU to provide a reference document for all critical instruments and to label these instruments in the field.
10,007.0 pounds
147895

2013-04-05
South Flare; #3 SRU; Area 1 Fuel Drum: Boiler B-7, Boiler TB-01, MDH Heaters; Area 2 Fuel Drum: Reformer Charge Heater; Hydrocracker Boilers Fuel Drum: Boiler B-5, Boiler B-6
South Flare; #3 SRU; Area 2 Fuel Drum: Reformer Charge Heater
Cause: On April 5, 2013 at approximately 08:47, Valero experienced excess emissions of Sulfur Dioxide and Hydrogen Sulfide at the South Flare, the #3 Sulfur Recovery Unit (SRU), and several refinery fuel gas fired sources due to a loss of power to the refinery's Distributed Control System (DCS). The DCS is a computerized system used to monitor and control the refinery process units. At the time of the incident, the most refinery units were shutdown for planned maintenance, only the Reformer, Naptha Hydrotreater (NHT), MiddleDistillate Hydrotreater (MDH), #3 SRU, and the four boilers remained in service. In order to perform work on the electrical distribution system, a temporary generator was installed to power vital loads, including the DCS. Additionally, the DCS Uniterruptible Power Supplies (UPSs) were bypassed for protection so that battery backup was not available. This temporary power generator dropped offline due to loss of communications between the generator and the engine driving the generator. The root cause of the loss of communications was a loose termination connection on a communications cable. The loss of the DCS caused the immediate shutdown of the remaining refinery units. Upon shutdown of the #3 SRU, field operators cut stripping steam to the #2 Amine unit to prevent acid gas flaring. This allowed some H2S to enter the refinery fuel gas system which was then combusted to SO2 as the fired sources were returned to service. The bulk of the SO2 emissions came from the actuation of a Pressure Safety Valve in the MDH that vented H2S containing material to the South Flare.

Followup: Yes

Notes: The DCS was restored in less that 25 minutes. Valero restarted all four boilers, the #3 SRU, and the MDH. The Reformer Charge Heater was re-lit as part of a controlled shutdown and the NHT was shutdown. SO2 emissions from the North Flare occurred on 4/5/13 from 08:47 to 4/5/13 22:51 for a duration of 14.1 hours (14 hours and 6 minutes). An estimated 2417 pounds of SO2 and 10 pounds of H2S were released. Power to the DCS was quickly restored and the affected units were shutdown in a controlled manner. The rental company technician for the generator quickly identified the loose termination connection as the issue, corrected the loose termination, and placed the generator back online in approximately ten to fifteen minutes. Power to the DCS was quickly restored and the affected units were shutdown in a controlled manner. Valero requested a backup generator from the rental company as a spare for the one that had tripped, which arrived later that day.
2,417.0 pounds
147349

2013-03-15
North Flare
Cause: On March 15, 2013 at approximately 08:40, Valero experienced excess emissions of Sulfur Dioxide at the North Flare during a planned shutdown of the Hydrocracker/Hydrotreater Unit. Valero was conducting a normal shutdown for a planned maintenance turnaround. During start ups and shut downs, H2S containing gases can pass through the Pre-fractionator stripper and accumulate in the Fractionator Overhead Receiver. The Fractionator Overhead Recveiver has no means of removing this gas, so Valero must vent it to the flare to prevent the pressure safety valve from lifting. The root cause of excess sulfur dioxide emissions from the Hydrocracker/hydrotreater during start ups and shutdowns has been identified from previous incidents to be inherent to the original design of the unit.

Followup: No

Notes: As a corrective action for previous incidents, Valero designed a vent line that will direct the gases vented from the Fractionator Overhead Receiver to the refinery's HiJet so that these gases will no longer need to be flared during startups and shutdowns. Valero will install this vent line during this maintenance turnaround. SO2 emissions from the North Flare occurred on 3/15/13 from 08:40 to 3/16/13 00:00 for a duration of 15.34 hours (15 hours and 20 minutes). Valero completed the shutdown of the Hydrocracker/Hydrotreater Unit according to procedure. Valero will install the vent line designed to prevent the Fractionator Overhead Receiver from being flared.
1,057.0 pounds
147203

2013-03-08
North Flare
Cause: On March 8, 2013, at approximately 01:34, Valero experienced excess emissions of Sulfur Dioxide at the North Flare during the start up of the Hydrocracker/Hydrotreater Unit. On March 5, 2013, Valero discovered an oil leak on an electrical transformer in the Reformer Unit. In order to de-energize and repair the transformer, Valero conducted a controlled shutdown of the refinery. The root cause of excess SO2 emissions from the Hydrocracker/ Hydrotreater during start up has been identified from previous incidents to be inherent to the original design of the unit. The most recent previous incident, SERC Incident # 12-05963, occurred on 9/3/12. As a corrective action for the 9/3/12 incident, Valero designed a vent line that will direct the gases vented from the Hydrocracker/Hydrotreater Fractionator Overhead Receiver to the refinery's HiJet so that these gases will no longer need to be flared during startup. Valero was planning to shutdown the Hydrocracker/Hydrotreater on 3/15/13 and install this vent line prioer to this unplanned shutdown to repair the transformer.

Followup: No

Notes: Valero completed the start up of the Hydrocracker according to procedure. Valero will shut down the Hydrocracker/Hydrotreater on 3/15/13 as originally planned and install the vent line designed to prevent the start up gases from being flared.
564.0 pounds
147091

2013-03-01
North Flare
Cause: On March 1, 2013 at approximately 16:15, Valero experienced excess emissions of Sulfur Dioxide at the North Flare due to an over-current trip of the East Crude Overhead Compressor. The West Crude Compressor was down for repairs and unavailable. The East Crude Overhead Compressor tripped offline at 15:23 and was started at 16:36. Valero was unable to immediately re-start the East Crude Overhead Compressor due to a 1 hour lockout timer that prevents re-start after tripping on over-current. When the trip occurred, Valero was in the process of shutting down another refinery unit for a planned maintenance outage. Normally, crude off-gas is lined up to this unit. The compressor tripped offline on over-current while Valero was redirecting the crude off-gas to an alternate destination. The pressure at this alternate destination was approximately 60psig higher than the compressor discharge prior to the switch. Valero determined the root cause of the trip to be that the electric motor on the East Crude Compressor was undersized and not capable of routing the crude off-gas to the higher pressure destination when fully loaded. Contributing factors include: 1. The West Crude Compressor was down for repairs and unavailable. 2. The crude tower was operating at elevated pressures due to degradation of the internal structures. This increased the work load (horsepower) on the off-gas compressor. 3. Approximately 40 minutes elapsed between the compressor trip and the reduction in Crude Unit charge rate.

Followup: Yes

Notes: Flaring from the Crude Overhead occurred from 15;23 to 16:38 and the Total Sulfur concentration in the North Flare returned to normal by 17:20. Valero immediately put all available crude overhead fin-fans in service to reduce crude overhead pressure and minimize flaring. Valero later cut crude charge rate to reduce the production of off-gas. Valero re-started the East Crude Overhead Compressor as soon as the lockout timer expired. To prevent recurrence: 1. Valero will upgrade both of the curde compressors with higher horsepower electric motors. 2. Valero will modify the "Loss of Crude Compressor" procedure to specify a more prompt reduction in crude charge rate. 3. Valero will modify the operations procedure for lining up crude off-gas stream to include unloading the compressor to control motor amps also to include running both compressors in parallel (if available). 4. Valero will bring the motor amp indications into the DCS for both compressors.
746.0 pounds
146616

2013-02-10
North Flare, South Flare, Area 1 Fuel Drum, Area 2 Fuel Drum, Area 4 Fuel Drum, HC Heaters Fuel Drum, HC Boilers Fuel Drum, #2 SRU, #3 SRU
Cause: On February 10, 2013, Valero Refining - Meraux LLC (Valero) experienced excess emissions of sulfur dioxide (SO2) and Hydrogen Sulfide (H2S) from all in service refinery heaters and boilers, the #2 and #3 Sulfur Recovery Unit (SRU) Incinerator Stacks, and the North and South Flares due to an unexpected shutdown of the #3 SRU. Shortly after the #3 SRU shut down the #2 SRU tripped offline as well. The #2 and #3 SRUs generated excess emissions due to these shutdowns and the subsequent start ups. Additionally, with both SRUs shutdown, the Amine units became saturated with H2S and were no longer capable of removing H2S from gaseous refinery process streams. As a result, the H2S concentrations in the refinery fuel gas and hydrotreater recycle gas systems began to increase. Elevated concentrations of H2S were then combusted in the refinery's heaters and boilers and in the North and South Flares. Root Causes: 1. Loss of 4160 Volt power to the #3 SRU Main Air Blower and #2 Lean Amine Pump. The investigation identified a 30 second power loss but was unable to identify the exact root cause because the plant power monitoring system was not running at the time. 2. The #2 SRU trip was caused by the failure to switch the acid gas interconnect line control scheme from flow control to pressure control. The episode occurred from approximately 06:42 on 2/10/13 to 01:13 on 2/13/13 for a duration of 66.5 hours.

Followup: Yes

Notes: Valero initiated the Sulfur Shedding Procedure and followed the MACT UUU SSM Plan to recover the #2 and #3 SRUs. Valero received reports of multiple citizen complaints called into the St. Bernard Fire Department. The wind direction of 2/10/13 placed the Valero Community Ambient Monitoring Site downwind of the refinery during the period of highest emissions and mobile ambient monitoring was performed by Valero and a third party. The highest single monitoring reading was 2.8ppm SO2; odors may be detected at this level.
93,347.0 pounds
158125

2014-08-16
Ultra Low Sulfur Diesel Hydrotreater Pressure Safety Valve
Cause: On August 16, 2014 at approximately 22:00, Valero exceeded the reporting threshold for sulfur dioxide (SO2) emissions at the South Flare. Valero calculates flare SO2 emissions based on continuous monitoring of flow and total sulfur concentration in the flare header. The reporting threshold is exceeded when the 24-hour aggregate exceeds the baseline average SO2 emissions by 500 pounds. Sour water generated in the Ultra Low Sulfur Diesel Hydrotreater (ULSDHT) is accumulated in the High Pressure Stripper Receiver before flowing to one of the two Sour Water Strippers. At approximately 20:00 on August 16th, Valero personnel began redirecting sour water from the #2 Sour Water Stripper to the #1 Sour Water Stripper. During this process, the liquid level increased in the Stripper Receiver and sour water entered the ULSDHT Fractionator, where it flashed into steam. This caused a sudden pressure increase in the overhead line which, in turn, caused a Pressure Safety Valve (PSV) to open to the South Flare. The root cause of this incident was an improper valve line-up. Operators lacked a clear and adequate procedure for switching between the two Sour Water Strippers, and the high-high alarms did not allow sufficient time to respond to the rising liquid level in the Receiver.

Followup: Yes

Notes: The feed to the ULSDHT was reduced and sour water was drained from the Stripper Receiver. The sulfur concentration in the South Flare returned to normal. Level alarms in the Stripper Receiver were set to a lower level, allowing additional response time during an upset. Operations procedures were revised to more clearly describe the process of rerouting sour water from one stripper to another.
831.0 pounds
156601

2014-06-07
South Flare
Cause: Leaking PSV on compressor in Diesel Hydrotreater Unit to blame for the release. On June 8, 2014 at approximately 12:00 hours, Valero exceeded the reporting threshold for Sulfur Dioxide (SO2) emissions at the South Flare. Valero calculates flare SO2 emissions based on continuous monitoring of flow and total sulfur concentration in the flare header. The reporting threshold is exceeded when the 24-hour aggregate exceeds the baseline average SO2 emissions by 500 pounds. Sulfur concentration in the south flare began to increase at 2100 on 6/7/14. At 0830 on 6/8/14, Valero began to flare sweet (low sulfur) propane while starting up the depropanizer section of the alkylation unit, which had been shut down for a week for repairs. At the same time as this startup, SO2 mass emissions increased to 100-120 lbs/hr. Valero executed its procedure for checking high sulfur sources (Process Safety Valves) and identified a leaking PSV in the diesel hydrotreater unit. Compressor was shut down, and the sulfur concentration returned to normal.

Followup: No

Notes: There remains some uncertainty about the accuracy of the monitoring at the south flare, as sulfur-free flaring from the alky depropanizer should not have increased SO2 emission rate. Valero provided verbal notification before reaching the emissions threshold. Valero implemented its procedure for checking high sulfur sources (process safety valves (PSV), process vents, etc) and identified a leaking PSV on a compressor in the Diesel Hydrotreater Unit. The compressor was shut down and the sulfur concentration in the South Flare returned to normal.
1,583.0 pounds
155365

2014-04-20
#3 sulfur recovery unit
Cause: Leak on the tubing location in #3 sulfur recovery unit.

Followup: No

Notes: Refinery submitted official letter to DEQ rescinding the verbal report that was given on 4/20/2014. The letter indicates that the release of sulfur dioxide fell below the 500 pounds per day threshold indicated in their environmental permit. No other reportable quantities were released.
153744

2014-02-10
#2, #3 SRU
Cause: On February 10, 2014 Valero Refining-Meraux experienced excess emissions of sulfur dioxide (SO2) and Hydrogen Sulfide (H2S) from all in-service refinery heaters and boilers, and the #3 Sulfur Recovery Unit (SRU) Incinerator Stack and the North Flare due to an unexpected shutdown of the #3 SRU. Later the #2 SRU tripped offline as well, resulting in excess emissions from that unit. The #3 and #2 SRUs generated excess emissions due to these shutdowns and the subsequent start ups. Additionally, the Amine units became saturated with H2S and were no longer capable of removing H2S from gaseous refinery process streams. Increased H2S concentrations in the refinery fuel gas and hydrotreater recycle gas systems resulted in excess emissions in the refinery's heater and boilers, and in the North Flare.

Followup: No

Notes: There seems to be a major equipment malfunction that occurred causing the incident however there is no mention of the cause or how it will be prevented in the future. All emissions point sources involved in the accident: No 1 Crude Heather, NTH Charge Heather, NHT Debut Reboiler, NHT Depent Reboiler, Platformer Charge Heater, Platformer Debut Reboiler, Vacuum Heaters, No 2 Alky Reboiler, Hydrocracker/Hydrotreater/Fractionator Charge Heaters, Boiler B-5, Boiler B-6, North Flare Stack, SRU #2 Incinerator, SRU #3 Incinerator
23,734.0 pounds
153609

2014-02-07
North Falre, #2 SRU Incinerator, & Area 2 Fuel Drum
Cause: On 2/7/2014, Valero exceeded the reporting threshold for sulfur dioxide (SO2). While attempting to identify the source of the increased odor in the North Flare header, the #2 sulfur recovery unit (SRU) shutdown. Valero determined the root cause of the elevated sulfur in the North Flare and the unexpected shutdown of the #2 Sulfur Recovery Unit (SRU) to be open block valve(s) on the Flare Knockout Blowcase [i.e. operator error]. This blowcase is used to periodically drain liquids from either a nearby flare knockout pot or the sour water offgas line feeding the #2 SRU. Liquids are drained into the blowcase and are then pressurized out with natural gas to the #1 Sour Water Stripper. With one or more of the block valves out of position, H2S passed from the sour water offgas line into the North Flare header. Later, to remove the accumulate liquids, the blowcase was pressurized with the block valve(s) still open causing a surge in pressure and flow and possibly entraining liquids through the sour water offgas line to the #2 SRU main burner. The resulting disturbance in the flame pattern was detected by the SRU fire eyes and the unit shutdown.

Followup: Yes

Notes: Valero conducted a search for the source of sulfur in the North Flare as soon as it was detected. Valero initiated the refinery's sulfer shedding procedure and shifted sulfur loads to the #3 SRU after the #2 SRU shutdown. This incident is similar to an incident that occurred on 5/7/12. Valero discovered that one corrective action from this earlier event has not yet been completed. This action was to install check valve(s) on the lines that drain the sour water offgas line to the blowcase. These check valve(s) could have prevented the shutdown of the #2 SRU, but not the elevated H2S in the North Flare. In addition to installed these check valves, Valero will review the procedure for operating the blowcase and conduct refresher training with the operators. Valero will also modify the current piping configuration that allows water to accumulate in the sour waster offgas line, thereby eliminating the need to periodically drain this line using the blowcase. This work will occur during the next turnaround.
731.0 pounds
153218

2014-01-08
South Flare (EQT 0049, EPN 3-77)
Cause: On January 8, 2014, at approximately 21:00 hrs, Valero exceeded the reporting threshold for Sulfur Dioxide at the South Flare. Valero implemented its procedure for checking high sulfur sources (PSV's, process vents, etc.), but found no obvious discharge into the flare header. After performing several searches for the source and not finding any valves out of position, Valero compared several gas samples to the composition of the gas being flared in the South Flare. Because of similarities in composition, Valero believes that source of total sulfur for this incident was the recycle gas section of the Ultra Low Sulfur Diesel Hydrotreater (DHT). The unit was shut down and restarted on 1/7/14 due to a cold weather related instrument malfunction. Valero inspected all connections between the DHT recycle gas section and the South Flare but could not determine a definite source. Valero initially believed that the source of sulfur was likely a weeping Pressure Safety Valve (PSV) on the DHT recycle gas section, so all the PSV's nt hte DHT recycle gas section were sent out for testing and repair during shut down. SO2 emissions at the South Flare returned after turnaround and reinstallation of the PSVs, indicating that the weeping PSV was not the source. Valero now believes that the cause was a continuous source and the total sulfur concentration of the recycle gas became elevated due to the shut down and start up on 1/7/14. The total sulfur returned to baseline levels after the DHT returned to normal operating conditions.

Followup: Yes

Notes: South Flare SO2 emissions decreased below the RQ on 1/9/14. Valero continuously monitors the total sulfur and flow at the South Flare.
659.0 pounds