CHANGES CAUSE AN INCIDENT

 On August 29, 2024, at 6:45 p.m., flammable vapors were accidentally released from a reactor at a refinery in Houston, Texas, resulting in a fire at the facility. The incident resulted in $16.8 million in property damage.
At the time of the incident, employees noticed flames coming from the head of a reactor in the fluidized catalytic cracking unit (“FCCU”). The flammable vapor released from the reactor likely caught fire from autoignition because the reactor operated at 960 degrees Fahrenheit (℉), which is above the autoignition temperature for most of the hydrocarbons released. Unit operators put out the flames with a fire extinguisher. The company reported that over 400 pounds of flammable vapors were released during this incident.

The company’s investigation determined that the flammable chemicals were released through an 8-inch crack in the wall at the top (head) of the reactor. Additionally, the company found other cracks in the reactor that were up to 67 percent of the wall thickness. The cracks were created by a damage mechanism known as corrosion fatigue. Corrosion fatigue is caused by cyclically applied stress under corrosive conditions. Internal cracks formed at the top of the reactor, an area that was consistently exposed to sulfur-containing chemicals commonly found in petroleum refining. This sulfidation corrosion was coupled with temperature swings over 200℉, which applied stress to the vessel through expansion and contractions of the metal with the temperature changes. The company found that there had been more than 50 temperature cycles since 2011. Additionally, platform supports were added to the reactor head in 2001, contributing to the cracking by increasing the stress exerted on the vessel. Stress-assisted preferential sulfur penetration is the specific type of corrosion fatigue responsible for the 8-inch crack.

The investigation also revealed that the company was not inspecting the reactor’s walls for cracking because the site’s mechanical integrity program did not identify corrosion fatigue as a potential damage mechanism. The company attributed this gap to following industry standards that did not identify corrosion fatigue as a common FCCU reactor damage mechanism.

Probable Cause
Based on the company’s investigation, the CSB determined that the probable cause of the accidental release was an 8-inch corrosion fatigue crack through the wall at the top of the reactor. Adding platform supports to the top of the reactor contributed to the incident by increasing the stress exerted on the vessel during the temperature changes. The company’s mechanical integrity program contributed to the incident by not identifying corrosion fatigue as a potential damage mechanism for its FCCU reactor.

Source: CSB.gov

HUMAN FACTORS CAUSED A FURNACE TUBE RUPTURE

 On July 12, 2024, at 7:00 p.m., a mixture of nitrogen and benzene was accidentally released into the firebox of a fired heater. The benzene ignited, causing a fire at a facility in Texas. The company estimated that the incident resulted in $9.8 million in property damage.

The incident occurred while employees were restarting the fired heater after Hurricane Beryl damaged offsite power systems, disrupting water availability and causing a shutdown of the facility on July 8, 2024. Process fluid should circulate through the fired heater’s tubes during the unit startup. The company's investigation found that the process flow through the fired heater was reduced because two misaligned valves (open valves that should have been closed) allowed some of the flow to bypass the heater.
Without enough fluid flow to remove heat, the tubes reached temperatures as high as 1,900 degrees Fahrenheit, far above the safe operating temperature. The high-temperature condition weakened the tubes in the upper portion of the fired heater and caused some of them to rupture, likely from short-term overheating.

The company reported that the ruptured tubes released approximately 16,000 pounds of nitrogen and 630 pounds of benzene into the firebox. The operating burner flames ignited the flammable benzene, resulting in a fire.
The company's investigation reviewed the company’s process hazard analysis and determined that the existing instrumentation safeguards did not protect against low-flow or high-temperature conditions in the fired heater during startup. The investigation also found that human factors caused valve alignment errors that allowed some process flow to bypass the furnace. These included vague radio communications, multitasking due to a high startup workload, stress from the major hurricane, perceived time pressure from delays, and implementing an unfamiliar startup, which was infrequently conducted.
After the incident, the company provided its operations team with fired heater startup simulator training and improved the company’s instrumented safeguards for the fired heater. These instrumentation upgrades included an alarm and a safety interlock to protect the equipment when the temperature difference between any individual tube pass temperature and the combined process fluid temperature exiting the furnace indicates that there is insufficient process flow through the tubes.

Probable Cause
Based on The company's investigation, the CSB determined that the probable cause of the incident was ruptured process tubes in a fired heater. Short-term overheating likely resulted in the tubes rupture, releasing nitrogen and benzene into the firebox. The flames from the fired heater’s operating burners likely ignited the benzene. Human factors resulted in two valve misalignments that contributed to the incident by creating a low-flow condition through the tubes, which increased the temperature in the tubes. A lack of instrumentation safeguards to protect the fired heater from low-flow and high-temperature conditions also contributed to the incident.

Source:CSB.gov

H2S LEAK KILLS ONE AND SERIOUSLY INJURES ANOTHER

On May 29, 2024, at about 3:15 p.m., several pounds of hydrogen sulfide and carbon monoxide gas were released at a facility in Colorado. As a result of the release, one employee was fatally injured and another  employee was seriously injured due to inhalation of the gases.

The company's investigation found that at the time of the incident, two employees were performing maintenance work on a pump at the facility. The workers closed an isolation valve and removed approximately half of the bolts on the connection before water began leaking from the flange onto the floor. The workers and their supervisor determined that the isolation valve was not properly seated. The two workers left the pump house to get a tool to help close the valve. While the workers were gone, hydrogen sulfide and carbon monoxide gas began releasing into the pump house (which was approximately 400 square feet and 8 feet tall).
When the workers reentered the pump house, they experienced symptoms consistent with toxic gas exposure. One of the workers lost consciousness (“Worker One”) when trying to escape up a ladder. The other worker (“Worker Two”) escaped the pump house. Worker Two explained the situation to another supervisor, and emergency responders were contacted. A third supervisor and two other employees attempted to rescue Worker One, but they realized that the area was dangerous and tried to escape. During the escape, one of the attempted rescuers (“Rescuer One”) fell, appeared to be unconscious, and could not self-rescue. An air monitoring device that was lowered into the pump house sounded an alarm for both hydrogen sulfide and carbon monoxide, indicating the concentrations of the gases were above 20 and 35 parts per million, respectively. Because of the high concentrations of the gases, employees halted their rescue attempts and waited for emergency responders to arrive.
Emergency responders with self-contained breathing apparatuses were able to rescue the two employees from the lower pump house and transport them to a local hospital for medical treatment. Rescuer One died at the hospital later that day. Worker One survived and was released from the hospital after a few days. After the incident, The company classified the lower pump house as a confined space and installed continuous air monitoring equipment.

Probable Cause
Based on The company's investigation, the CSB determined that the probable cause of the incident was the pump’s leaking isolation valve that allowed hydrogen sulfide and carbon monoxide gas to enter the pump house when the flange was opened. Not identifying or controlling these toxic gases from being released in this part of the process contributed to the incident. Contributing to the severity of the incident was that the lower pump house was not classified as a confined space, which allowed employees to enter without safeguards such as respiratory protection, air monitoring, attendants, or a rescue plan.

Source: CSB.gov

WHY OPERATIONAL READINESS MUST BE CHECKED

 On March 17, 2024, at approximately 12:50 p.m., about 250,000 pounds of hydrogen and naphtha mixture were accidentally released into the firebox of a fired heater, where it ignited, creating a major fire at a Refinery in Texas. The company estimated that the property damage from the incident was $32 million.
The company's investigation revealed that three days before the incident, on March 14, 2024, the temperature of the tubes in the fired heater exceeded 1,200 degrees Fahrenheit, the heater’s operating limit. When the alarms indicated that the temperature exceeded the operating limit, operators at the facility lowered the temperature in the fired heater by reducing the fuel gas flow to the heater’s burners.
On March 17, 2024, the day of the incident, the same fired heater reached similar high temperatures, prompting operators to respond again. The situation escalated when two tubes within the fired heater ruptured, releasing hydrogen and naphtha into the firebox. The existing burner flame ignited these flammable hydrocarbons, resulting in a major fire.
The company’s investigation found that fire blankets and insulation material (“debris”) were present inside the failed tubes. The company determined that this debris was likely left inside the equipment after the conclusion of maintenance work (turnaround) that had been done three weeks earlier. This debris restricted the flow through the tubes, causing an increase in the temperature of the metal walls and ultimately leading to the tube failures. Additionally, the fired heater was not equipped with individual pass flow instrumentation. The company’s metallurgical examination determined that the tubes ruptured because of a combination of creep damage (which results from prolonged exposure to stress at elevated temperatures) and short-term overheating.

The company’s investigation revealed that the refinery’s process for ensuring that equipment was clean before resuming operations did not include checks of piping or fired heater tubes. Additionally, The company determined that its operational readiness programs assessed only the external status of piping and valves and did not evaluate their internal condition.

Probable Cause
Based on The company’s investigation, the CSB determined that the probable cause of the hydrogen and naphtha release was that tubes in the fired heater ruptured due to a combination of creep damage and short-term overheating. Flames from the fired heater’s burners ignited these flammable materials, resulting in the fire. Reduced flow through the fired heater’s tubes, caused by debris left inside the equipment after maintenance, contributed to the incident.

Source:CSB.gov

INCIDENT DUE TO REACTIVE CHEMICALS AND PLUGGING OF RUPTURE DISC NOZZLE

 On February 13, 2024, at 11:59 p.m., a titanium tetrachloride and hydrogen chloride vapor mixture was accidentally released at a facility in Mississippi. Two employees were seriously injured when they inhaled some of this toxic vapor.

At the facility, a process stream containing titanium tetrachloride and solids is sent through a cyclone for separation. The separated solids fall through piping directly connected to a tank filled with water (“water tank”) to cool them. Over time, this piping regularly plugs with solids, and workers periodically unblock it in order to continue operations.
Before the incident, two employees were clearing the piping when the pressure in the water tank increased, causing a separate pipe connecting the water tank to a scrubber to break. Approximately 280 cubic feet of a mixture of titanium tetrachloride and hydrogen chloride escaped from the broken piping, exposing the two workers to the toxic vapor. After inhaling this vapor, the workers experienced respiratory problems, which worsened over the next few hours. Both employees were transported to a hospital, where they were admitted for treatment.
The company’s investigation determined that the high-pressure condition inside the water tank was created by a violent chemical reaction between titanium tetrachloride and water that generated hydrogen chloride vapor and heat. Liquid titanium tetrachloride had accumulated within the plugged piping from an upstream spray injection system. When the workers cleared the solids from the piping into the water tank, the liquid titanium chloride also entered the water tank, triggering the chemical reaction. Although the water tank was equipped with a rupture disc to protect the equipment from high-pressure conditions, the rupture disc did not activate during the incident because its inlet piping was blocked with solids. The investigation also found that although previous high-pressure events had occurred, the company's employees were not required to wear respiratory protection for the pipe-clearing activity.

Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was a reaction between titanium tetrachloride and water, which generated hydrogen chloride vapors. High-pressure conditions developed in the system and broke the piping connected to the water tank, releasing toxic vapor into the surrounding air, which seriously injured two employees. The water tank’s rupture disc did not activate because its inlet piping was plugged with solids, contributing to the incident. Not wearing respiratory protection during the pipe-clearing work contributed to the severity of the incident.

Source: CSB.gov

REACTIVE CHEMICALS INCIDENT

On December 29, 2023, at 1:45 p.m., a storage tank exploded, creating a fire at a facility in Connecticut. The explosion and fire seriously injured one contractor and the property damage was approximately $5.8 million.

The company's investigation found that a 10,000-gallon epoxy-lined steel storage tank exploded from a chemical reaction inside the tank. At about 1:00 p.m. on the day of the incident, workers finished transferring about 4,000 gallons of organic material containing methylene chloride, tetrahydrofuran, toluene, xylenes, trimethylbenzene, and naphthalene into the storage tank from another vessel at the facility. Chemical compatibility testing was not performed before making this transfer. The company's investigation concluded that adding 4,000 gallons of material to the storage tank agitated the existing 6,000 gallons of sludge already inside the tank, starting an unintended chemical reaction.
The sludge contained hydrogen peroxide, organic peroxides, and metal ions, including cobalt, iron, nickel, and chromium. Agitating this material likely started a chemical decomposition reaction between the organic and peroxide components in the presence of metals. This reaction produced vapor (including oxygen gas) and generated heat. At 1:45 p.m., the flammable vapor within the hot tank ignited (autoignition), and the storage tank exploded. The explosion created a fire that seriously injured a truck driver who was at the facility to make a chemical delivery into a different tank.
The company  did not estimate the amount of combustion products released when the storage tank exploded. To prevent a similar incident, The company stated that the company plans to stop handling oxidizers in this equipment, perform compatibility testing before transferring materials, and routinely clean its tanks.

Probable Cause
Based on The company's investigation, the CSB determined that the probable cause of the incident was the mixing of reactive chemicals within a storage tank, which generated heat and oxygen. The heat from the reaction ignited the flammable vapor in the tank (autoignition), resulting in the explosion. The failure to confirm chemical compatibility before transferring material into the storage tank contributed to the incident.
Source:CSB.gov

BE CAREFUL WITH EXPLOSIVE MIXTURES

 On October 13, 2023, at approximately 9:45 a.m., a mixture containing tetrazine and lead styphnate detonated at a facility in Nebraska. The explosion fatally injured one operator.

At the time of the incident, the company was producing priming compound, the ignition component used in firearm ammunition. The priming compound had already completed the first mixing cycle, and the operator was scraping the partially mixed priming compound off the mixer blade and the sides of the mixing bowl with a silicone spatula. While performing this task, the priming compound detonated and fatally injured the operator.
The company’s investigation evaluated the possibility that the explosion was ignited by static electricity. The explosive material’s moisture content was within the proper range, and the spatula, the room floor, and the operator’s shoes passed a conductivity check before the incident occurred. The company’s investigation concluded that these conditions showed that the explosive material should have been adequately desensitized, making static electricity an improbable ignition source. Instead, the company’s investigation concluded that the detonation was most likely ignited by the energy applied from mixing a dry area of explosive mixture with the silicone spatula.
After the incident, the company eliminated the need for operators to scrape the bowl and mixer blade until the entire mixing stage was completed, limiting the time that an operator was near the unmixed explosive components.

Probable Cause
Based on the company’s investigation, the CSB determined that the probable cause of the detonation was the energy applied by manual mixing to the explosive mixture.

Source: CSB.gov

ON THE 41ST ANNIVERSARY OF BHOPAL - WHERE IS PSM IN INDIA?

Tonight is the 41st Anniversary of the Bhopal Disaster. What is the status of PSM in India? Have we learnt the lessons? My take:

GOVERNMENT AND LAWS:

Till today, there is no specific legislation in PSM in India. The oil and gas industry OISD-GDN- 206 specifies guidelines to be followed. There is talk about bringing in PSM legislation but I have not heard of anything released till now.

INVESTIGATION OF INCIDENTS AND PUBLIC SHARING OF REPORTS:

There is still a shroud of secrecy when any incident investigation is carried out by an expert committee. The results are still not shared publicly. The Sigachi industries  blast investigation report is mentioned in an article in the Hindu newspaper "Though the report was submitted to the government in September, it has not been publicly shared nor has any action been initiated against the company management".

Read the article in this link: 

https://www.thehindu.com/news/national/telangana/sigachi-report-production-enhancement-without-trained-staff-and-safety-measures-led-to-the-explosion/article70307963.ece

Unless we share and learn for incidents, we will not be able to prevent another incidents. "There are no new incidents".

The number of incidents of gas/chemical leakage from Government data presented in parliament for 2018 to 2022 is given below (Source:  https://www.data.gov.in/resource/state-wise-number-data-received-chief-inspector-factories-cifs-gas-chemical-leakage)

The LG Polymer gas leak incident in Visakhapatnam occurred in May 2020 in AP. 

 

 INDUSTRY:

A lot of progress has been made in the large chemical process industries regarding PSM. All the large players in the industry (Public limited) and major private sector players have implemented either the OSHA 14 element PSM system or the 20 element risk based PSM system of CCPS.

Industry bodies like ICC, FICCI, FAI, CCPS etc have raised awareness of PSM by seminars and workshops.

There is a lot of activity going on in AI and ML and other technologies but the leadership must realize that these are only tools that can act as enablers. Hard decisions need to be taken by management who are competent in process safety. There is a lack of Process Safety competency requirements for directors on the boards of chemical processing industries. 

 ACADEMIA:

Academia in India is now offering more courses in process safety. Recently IIT Madras has started a PG diploma in process safety. See the link https://code.iitm.ac.in/processsafety 

WAY FORWARD:

Presently, the improvements in PSM in India are being carried out in Silos. The government must involve Industry, Academia, subject matter experts and public bodies to chart out an integrated approach towards improving process safety in India. Investigation and sharing of lessons learnt from fatal incidents should be made publicly and centrally available. 

 

 

 

 

 

COMMUNICATION IS VERY IMPORTANT WHEN A JOB IS RESUMED AFTER A TIME GAP

On May 23, 2023, at about 8:20 a.m., approximately 60,000 pounds of naphtha were accidentally released at a refinery Oklahoma. The released naphtha vaporized and ignited within seconds of the initial release. The fire fatally injured one employee and seriously injured another employee. The company estimated that the incident resulted in approximately $8 million in property damage.

The company's investigation found that a flow control valve (“control valve”) in the naphtha hydrotreating unit was malfunctioning. On May 22, 2023, the day before the incident, two maintenance employees were assigned to troubleshoot the control valve. The maintenance team conducted a walkthrough with an operator, who issued them a safe work permit. Operators bypassed flow around the control valve to maintain the desired flow rate to downstream equipment. An operator also closed the isolation valve upstream of the control valve. The isolation valve downstream of the control valve remained open, however, and the drain valves on each side of the control valve remained closed. As a result, the equipment contained flammable liquid naphtha, which the company did not isolate, lock out, or otherwise prepare for equipment opening work.
The control valve was opened from its closed to its fully open position, and the maintenance employees concluded that it was “hung up” and not working correctly. The maintenance employees planned to disassemble the valve and confirmed that there was a gasket set for it. With the workday nearing its end, the company personnel decided that the control valve work could continue the next workday while the control valve remained bypassed overnight.
On the day of the incident, the same maintenance employees returned to continue working on the control valve. A different operator authorized the maintenance employees to use the same safe work permit from the previous day. The operator understood that the scope of work was limited to troubleshooting the control valve. Consequently, no field review of the job took place. About 15 minutes after the maintenance employees returned to the work location, naphtha began releasing from the control valve’s bonnet flange.

The flame in a nearby fired heater likely ignited the flammable hydrocarbon vapor. The fire engulfed the two maintenance workers, but they escaped the area. Emergency responders transported the two workers to hospitals by helicopter, where they were admitted for treatment of their serious burn injuries. Three days later, on May 26, 2023, one of the workers succumbed to their injuries and died.
The investigation revealed that six of the eight nuts had been removed from the control valve’s bonnet flange, which was the typical practice at the refinery when preparing to access the internal components. The control valve’s bonnet flange had been partially disassembled while its downstream isolation valve was open, and it contained naphtha at 250 pounds per square inch gauge pressure and 425 degrees Fahrenheit. It is unknown whether the maintenance employees thought the system was safe to disassemble the control valve or did not recognize the hazard of disassembling the pressure-retaining components.

Probable Cause
Based on the company's investigation, the CSB determined that the cause of the incident was disassembling a control valve’s pressure-retaining bonnet flange during a maintenance activity. The control valve was not isolated from the operating process before performing this work.
Miscommunicating the scope of the work or not recognizing the hazards of disassembling the control valve’s pressure-retaining components led to safe work (energy isolation) practices not being performed, which contributed to the incident.

Source:CSB.gov

ARE YOU CARRYING OUT VIBRATION ANALYSIS FOR ROTATING EQUIPMENT TO PREDICT FAILURES?

On May 15, 2023, at 9:32 a.m., an accidental release of naphtha caught fire, fatally injuring one worker at a Refinery in Texas. The company estimated that this event resulted in $829 million in property damage.
On the morning of the incident, two employees were completing an equipment oil change on an elevated platform above a pump that was supplying naphtha to downstream equipment. The pump’s coupling failed, reducing outlet flow and creating high vibration that broke a small bore (¾-inch) piping section, releasing flammable naphtha. Employee 1 was on the platform cleaning up the work area while Employee 2 was carrying a bucket of oil down the stairs from the platform. Employee 2 smelled the released hydrocarbon and saw what looked like a steam cloud. Within minutes of the release, the flammable vapor ignited 

The heat from the fire ruptured piping and damaged other equipment. Employee 2 was able to exit the unit before the flammable naphtha ignited. Employee 1 did not escape from the elevated platform and was fatally injured by the fire.
The company's investigation found that a pump inspection in June 2022 had identified damage to the coupling of the pump but did not recommend any repairs. During the release in this incident, the pump’s motor continued to operate and spin the damaged coupling. The heat generated by the friction ignited some of the released naphtha, resulting in the fire. The investigation also found that according to the company’s mechanical integrity program, vibration analysis should be performed every two months to predict pump failures, including coupling failures. The last vibration analysis test on the pump was completed in October 2022, seven months before the incident. The company reported that approximately 102,000 pounds of naphtha and light hydrocarbons were released.

Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was a pump coupling failure that created high vibration, breaking a section of small-bore piping and releasing flammable naphtha. With the pump’s motor continuing to operate, the coupling failure also created enough heat (friction) to ignite some of the released naphtha vapor, creating the fire.
The company's mechanical integrity program contributed to the incident by not repairing the damaged coupling identified by the inspection. Additionally, the company did not perform its required vibration analysis on the pump, which could have predicted the coupling failure. 

Source:CSB.gov

ARE YOU REPORTING PASSING VALVES AS A PROCESS SAFETY NEAR MISS?

On May 4, 2023, at 6:25 a.m., approximately 790 pounds of a hydrocarbon mixture containing about 7,000 parts per million (ppm) of hydrogen sulfide were accidentally released at a Refinery in California. Exposure to the toxic hydrogen sulfide vapor seriously injured one employee.
The company's investigation found that on the day of the incident pressure within a distillation column at the facility began to increase significantly. Three field operators worked to open a valve to bypass flow around the distillation column’s overhead accumulator (“drum”) to reduce the pressure. While opening the bypass valve, the operators found that the indication on the field pressure gauge did not align with the value that the pressure transmitter reported to the computer control system. When there is this kind of instrumentation discrepancy, the company expects its operators to replace field gauges during normal troubleshooting activities. To that end, a fourth operator brought a new pressure gauge to the top of the deck to replace the existing gauge.
Per the facility’s gauge replacement procedure, the operators closed two valves to isolate the pressure gauge from the process. Additionally, the operators discovered a note on the pressure gauge that stated “Valve Issue” with an arrow pointing to the two valves on the drum. One of the valves was used to isolate the pressure gauge and the other valve was used to isolate the drum . Because the valve used to isolate the drum was visibly broken, the operators assumed that the note referred to it. However, unknown to the operators, the valve used to isolate the pressure gauge could not fully close due to an internal obstruction.
With the valve isolating the pressure gauge appearing to be closed, one of the operators began unscrewing the pressure gauge to relieve any residual pressure. The operator did not identify a potential leak as there was no indication of residual pressure while unscrewing the last threads of the pressure gauge. After the gauge was removed, however, the process pressure likely dislodged debris in the piping, causing the process stream to discharge into the atmosphere. This released flammable hydrocarbons containing hydrogen sulfide, exposing all four operators to the toxic hydrogen sulfide. Post-incident, Marathon found that the pressure gauge was plugged.

The company's investigation also revealed that none of the operators wore respirators to protect themselves from inhaling the hydrogen sulfide vapor. As a result, exposure to the toxic hydrogen sulfide caused the four operators to lose consciousness. Three operators regained consciousness and climbed down from the drum deck. Emergency responders rescued the unconscious operator. The operator was transported and admitted to a hospital for medical treatment. Emergency responders also reinstalled the pressure gauge to stop the release. The investigation did not identify who wrote the note or find any work order to repair either valve.

Probable Cause
Based on the company's investigation, the CSB determined that the accidental release was caused by company's failure to effectively isolate the piping before removing the pressure gauge. Not using PPE that could protect the workers from exposure to hydrogen sulfide contributed to the severity of the incident. The company's mechanical integrity program, which did not replace the broken valve after it was identified in the field, also contributed to the incident.

Source:CSB.gov

EMPTY TANKS MAY NOT BE EMPTY!

 On April 3, 2023, at approximately 1:45 p.m., flammable vapor within a storage tank ignited, resulting in an explosion and a major fire at a Tank Terminal in Louisiana. The incident seriously injured two contractors and caused over $15 million in property damage.

The company provides storage tanks for customers to store liquids in large quantities. The company's investigation found that before the incident, one of the company’s 8.4-million-gallon storage tanks (“tank”) contained natural gas condensate that was drained from the tank in 2021. After removing the flammable liquid, the tank’s manways were opened for several weeks for maintenance work inside the tank.
On August 29, 2021, Hurricane Ida made landfall south of the facility as a Category 4 hurricane with maximum sustained winds of 150 miles per hour. After the hurricane, the company discovered that a hatch covering the opening for the ladder to access the tanks’ internal floating roof had broken off.
In 2023, the company hired a contractor to weld a new hatch cover onto the tank. As two contractor employees were working on top of the tank, flammable vapor inside the tank exploded, seriously injuring both workers. The two contractor workers were transported by helicopter and admitted to a hospital for treatment of their severe burn injuries while other emergency responders fought the resulting tank fire
Flammable hydrocarbon liquid burned in the tank for about nine hours before emergency responders extinguished the fire.

The company's investigation revealed that the company issued a hot work permit for the grinding and welding to install the new hatch cover. Air monitoring conducted around the access ladder opening and up to two feet inside the tank’s opening showed no flammable vapors. The company issued a work permit that required the contractor workers to cover the opening with a fire blanket and to perform continuous air monitoring on the tank’s roof.
Before issuing these permits,  workers reviewed the facility’s storage tank inventory records, which indicated that the tank was empty. However, the tank’s piping was not locked out, and no manways were opened to confirm that the tank contained no residual flammable liquid. As a result of the incident, the company created a tank database showing the operational state of each tank, identifying whether the tank is in service, cleaned, degassed, or gas-free.

Probable Cause
Based on company's investigation, the CSB determined that the probable cause of the incident was the presence of flammable hydrocarbon vapors inside the tank while hot work (grinding or welding) was being performed on the tank’s roof. Not thoroughly draining, cleaning, and purging the tanks to remove the flammable material before starting the hot work contributed to the incident. Additionally, ineffective air monitoring practices to identify the presence of flammable hydrocarbon vapor contributed to the incident.

Source:CSB.gov

FLAME OUT CONDITIONS IN A HEATER IS DANGEROUS!

On February 18, 2023, at 2:50 p.m., flammable fuel gas ignited, resulting in an explosion of a boiler at a  Coke Plant in Ohio. Estimated property damage was approximately $1 million.

On the day of the incident, tubes inside the boiler were carrying water, and a burner inside the structure heated the water to produce steam. The boiler’s burner was combusting fuel gas (composed of natural gas and coke oven gas) to heat the water to produce steam. The forced draft fan that introduced air to the burner unexpectedly shut down, and without air being fed to the burner, the burner flame went out. Flammable fuel gas continued to enter and accumulate in the boiler, however, and about ten minutes later, the accumulated flammable gas ignited, resulting in an explosion. The company determined that the oxygen analyzer installed in the boiler was the source of ignition. The explosion caused extensive damage to the boiler and ductwork.
The company's investigation found insufficient alarms to alert operators that the forced draft fan had shut down. A visual alarm signaling loss of air had activated on a control room screen, but the operator was looking at a different screen at the time of the incident and did not see the alarm. In addition, there were no cameras installed to monitor the burner flame and no dedicated video monitor for operators to view the boiler exhaust, which could have indicated an operational problem with the boiler. After the incident, the company’s corrective actions included installing audible alarms for the boiler fans, cameras on the burners, and a dedicated video monitor for the boiler exhaust.
The company did not determine the amount of the combustion products accidentally released, but the company estimated that approximately 28,000 cubic feet of fuel gas had accumulated before the explosion.

Based on the company's investigation, the probable cause of the incident was the ignition and explosion of accumulated flammable fuel gas inside a boiler. The flammable fuel gas accumulated in the boiler after the air flowing to the boiler’s burner stopped, and the burner flame went out. Insufficient safeguards to prevent fuel gas from flowing to the boiler when the burner flame went out contributed to the incident.

Source:CSB.gov

ARE YOU CONDUCTING COMBUSTIBLE GAS MONITORING PROPERLY?

On Friday, February 3, 2023, at approximately 10:46 p.m., a flash fire was accidentally released from a product purge vessel (“vessel”) flange during planned maintenance activities at a facility in Louisiana. The fire seriously injured four contract workers.

On January 29, 2023, the facility shut down its polyethylene unit for planned maintenance. Following the shutdown procedure, operators purged and isolated the vessel in preparation for maintenance. The facility hired a contractor company to support the planned maintenance activities, which included replacing internal filter elements. The maintenance activity involved hot work, an operation that uses flames or can produce sparks.
On February 3, 2023, the company issued a safe work permit to remove bolts from the top head of the vessel. Most bolts were removed using tools that the company considers low-energy hot work tools. However, the remaining bolts could not be removed with these tools. As a result, a safe work permit to perform high-energy hot work was issued to remove the remaining bolts with a grinder (a high-energy hot work tool).
The vessel is connected to a flare system to vent unreacted gases. At the time of the incident, a series of valves were available to isolate the vessel from the flare system, but only one valve was closed to isolate the flare. While the valve was closed, it did not fully prevent flammable gas from flowing from the flare system into the vessel. In addition, air was also present within the vessel. The flammable gas mixed with air, creating a flammable atmosphere inside the vessel.
The company investigation found that not all of its hot work policy requirements were met before using the grinder to cut the remaining bolts, such as isolating the vessel through blinding or air gapping (the company’s preferred method) and using an inert gas (such as nitrogen) to purge residual materials from the system. Although the company conducted atmospheric monitoring outside the vessel, which showed a zero percent lower explosive limit (indicating that the atmosphere was free of explosive and flammable gases), no combustible gas monitoring of the atmosphere inside the vessel was performed where the bolts were removed.
Hot metal fragments from grinding the bolts ignited the flammable vapor within the vessel, resulting in a flash fire that exited from the vessel’s flange, seriously injuring four contract workers. The injured contract workers were transported to a hospital and admitted for medical treatment.
The company reported that a small quantity of flammable chemicals (less than 10 pounds) had entered the vessel. These chemicals likely included a mixture of hydrogen, methane, ethane, ethylene, isopentane, hexane, hexene, and nitrogen. When these chemicals ignited, the flash fire erupted from the vessel flange with an unknown fraction of the combustion products.

Probable Cause
Based on the company investigation, the CSB determined that the probable cause of the flash fire was performing hot work (grinding) to cut flange bolts on a pressure vessel containing a flammable atmosphere. The ineffective application of the hot work policy contributed to the incident by relying on a single isolation valve to prevent flammables from entering the vessel from the flare system and not performing combustible gas testing of the flammable atmosphere within the vessel before permitting this work. Had combustible gas testing of the atmosphere within the vessel been conducted before permitting the work, this incident likely could have been prevented.

Source:CSB.gov

ARE YOU MEASURING FURNACE TUBES SKIN TEMPERATURE RIGHT?

 On January 21, 2023, at 1:58 p.m., a mixture of hydrogen and hydrocarbons was accidentally released into the firebox of a fired heater, where it ignited, resulting in a large fire at a refinery in Louisiana. The  property damage from the incident to be approximately $34.1 million.

According to the company's investigation, four months before the incident, a contractor performed an infrared (“IR”) scan of the fired heater and found elevated temperatures in the heater, with one tube section operating above 1,300 degrees Fahrenheit (℉). At the time, the contractor concluded that the high temperatures were measurements of the scale and oxidation on the outside surface of the tubes, not the tube’s metal wall temperature. After the incident, the company determined that the IR temperature measurements taken before the incident were likely accurate, but they had been misinterpreted. As a result, the infrared temperature data was not used to adjust the operating conditions of the fired heater, which could have lowered the tube temperature within the design limit.

The company's  investigation determined that on the day of the incident, the fired heater’s tubes experienced another high-temperature event, leading to a tube rupture. The unit had automatically shut down due to a problem in another part of the process. During this shutdown, the hydrogen and hydrocarbons flowing through the fired heater’s tubes stopped, but the burners continued operating because the fuel gas control valve did not fully close. Without fluid flow through the tubes to remove heat, the tube’s temperature exceeded 1,400℉. Operating at this temperature caused short-term overheating, further degrading the tubes’ integrity. As the fired heater was restarted, a tube ruptured (Figure 2), releasing a flammable mixture of hydrogen and hydrocarbons into the firebox, where flames from the gas-fired burners ignited it and resulted in a fire at the facility. The investigation concluded that the tube failure was likely the result of a combination of localized creep damage (which results from prolonged exposure to stress at elevated temperatures) and short-term overheating.

The company estimated that about 51,000 pounds of diesel, 160 pounds of hydrogen, and 560 pounds of methane were released. After the incident, the company installed larger fired heater viewports to allow for improved infrared scans of the tubes and installed instrumentation to monitor temperature.

Probable Cause
Based on the company investigation, the CSB determined that the probable cause of the incident was a fired heater tube rupture from a combination of creep damage and short-term overheating. Flames from the fired heater’s burners ignited the released flammable mixture of hydrogen and hydrocarbons, resulting in the fire. Insufficient temperature instrumentation and an inadequate infrared scanning program contributed to the incident.

Source:CSB.gov

ARE YOUR FIRED HEATERS SAFEGUARDS RELIABLE?

 On December 23, 2022, at about 4:08 a.m., approximately 1,800 gallons of naphtha were accidentally released into the firebox of a fired heater, where it ignited, resulting in a serious fire at a Refinery in  Arkansas. The company estimated that the property damage from the incident was $36 million.

The company's investigation identified that ambient temperatures at the facility dropped to 12 degrees Fahrenheit by 11:00 p.m. on the night of the incident. This cold weather caused operational issues with some instruments and controls, leading to low hydrocarbon flow through the tubes of a fired heater. The decreased flow resulted in reduced heat transfer, which likely caused the metal temperatures in the tubes to rise significantly. This high-temperature condition ultimately caused a tube to rupture, releasing flammable hydrocarbons into the firebox, where the existing burner flame ignited them. The company commissioned a metallurgical examination and found that the tube ruptured due to creep damage (which results from prolonged exposure to stress at elevated temperatures) and short-term overheating.

The company's investigation found that some instruments and controls were not effectively winterized for cold weather conditions, which impacted their performance. As a result, some controls were put in manual mode, and some alarms were interpreted by employees as unreliable, leading to reduced hydrocarbon flow through the tubes and elevated tube wall temperatures. Additionally, the fired heater was not equipped with instrumentation to measure the tube’s metal wall temperatures. The company's investigation further revealed that the process hazard analysis for this fired heater relied on safeguards that were insufficient or not in place to prevent low tube pass flow conditions. In addition, a low-flow safety interlock did not work because it was improperly set.

Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the naphtha release was a tube rupture, which resulted from creep damage and short-term overheating. Flames from the fired heater’s burners ignited the flammable hydrocarbons, resulting in the fire. Fired heater safeguards that were not in place or improperly set, in addition to inadequate winterization of flow control equipment, contributed to the incident. Had the fired heater been equipped with instrumentation to measure the tube’s metal wall temperatures and other safeguards been in place, this incident likely could have been prevented.

Source: CSB.gov

ACCIDENT DURING PIGGING

 On October 11, 2022, at approximately 2:00 p.m., 2,200 cubic feet of natural gas under high pressure were released from a 20-inch gas pipeline at an Energy in New Mexico. The high-pressure natural gas forcefully impacted a contractor, resulting in one serious injury.
On the day of the incident, an employee and a contractor were tasked with passing a large-diameter cleaning tool (called a “pig”) through the 20-inch pipeline. This “pigging” procedure involved sending a pig with a diameter slightly larger than the pipe to clean and displace fluids within the pipeline. High pressure pushes the pig through the piping, ending in a section (called a “receiver”) designed to capture and hold the pig until removal. The receiver was newly installed and being used for the first time at the time of the incident.
When the two workers went to remove the pig from the receiver, the pressure in the receiver was above 1,150 pounds per square inch (“psi”). To safely remove the pig, the pressure needed to be reduced by relieving it through a vent valve located at the top of the receiver. The contractor initially tried to remove the plug from the vent valve to relieve the pressure but found that the plug could not be removed with hand tools. This indicated that there could be pressure between the valve and the plug, forcing the threads tightly against each other. The contractor concluded that the vent valve might be leaking and decided to relieve the pressure inside the receiver using the drain valve instead, which was located at the bottom of the receiver 

The company's investigation of the incident found that the 90-degree fitting (elbow) was not properly tightened, allowing it to turn freely. Because the elbow was not properly tightened, when the contractor applied a wrench to the valve stem and began opening the 2-inch ball valve on the drain piping, the valve rotated to the left and fully opened. The 1,150-psi natural gas forcibly discharged toward the contractor’s left leg, launching the contractor approximately 50 feet away from the source of the release, resulting in a serious injury. The contractor was transported by helicopter and admitted to a hospital for medical treatment.
Probable Cause
Based on company's investigation, the CSB determined that the probable cause of the incident was the insufficient tightening of the 90-degree fitting, which resulted in the full opening of the drain valve and the rapid and forcible release of natural gas from the receiver. The leaking vent valve at the top of the receiver also contributed to the incident. The non-welded drain piping, which was able to turn freely when the valve was opened, contributed to the severity of the incident.

Source: CSB.gov

THE LAST "TO" IN "LOTOTO" IS VERY IMPORTANT!

 On September 22, 2022, at approximately 9:00 a.m., a liquid mixture comprised of aniline, formalin, and hydrochloric acid was accidentally released, seriously injuring one contractor at a chemical manufacturing facility in Louisiana 

On September 20, 2022, two days before the incident, an off-site power outage caused an immediate loss of process flow in the methyl diamine unit. The lack of flow allowed solids to form throughout a piping system. Company personnel were clearing the solids from this piping on September 22 when the incident occurred.
At approximately 9:00 a.m. on September 22, two contract workers began opening a flange connection in the piping system. After the flanged connection was fully opened, an amount (approximately 28 ounces) of toxic and corrosive liquid containing aniline, formalin, and hydrochloric acid sprayed from the open-ended piping. Some of the released liquid contacted the face and neck of a third contract worker (“hot zone attendant”). The hot zone attendant was present to monitor the safety of workers inside the “hot zone”—a 30-foot diameter area marked by red barricade tape—and to help decontaminate any workers leaving the hot zone. While the workers inside the barricade were wearing personal protective equipment (“PPE”) that included chemical suits with hoods and full-face supplied air respirator masks, the hot zone attendant wore a chemical suit and hood but was not wearing face protection.

After being sprayed with the toxic and corrosive liquid, the hot zone attendant first showered in the unit and then again at the site’s medical facility. The hot zone attendant was then transported to a hospital, admitted for inpatient care, and successfully treated for exposure to aniline.
The company's investigation found that the hot zone attendant did not wear face protection because the operations team did not recognize the potential for pressurized liquid aniline to remain in the piping system. Energy isolation work (often referred to as line breaks) performed after the power outage involved opening multiple other piping connections, including a valve at the high point in the piping system. The operations team believed that this work had removed pressure from the system. A post-incident review of the process data, however, showed that pressure remained in some areas of the piping system. The company’s energy isolation plan did not include a review of the available local or computer control system data to ensure that the piping was not under pressure.

Probable Cause
Based on company's investigation, the CSB determined that the probable cause of the accidental release was the opening of the flange connection while portions of the piping contained pressurized liquid. The company's energy isolation plan contributed to the incident by not ensuring the piping was depressured before workers began disassembling the flange connection. Allowing a worker near this equipment opening activity who was not wearing protective equipment that could shield the worker’s face from being sprayed with the toxic and corrosive process liquid contributed to the severity of the incident. Had the worker been wearing protective equipment with a face shield, this incident likely could have been prevented. Additionally, reviewing available local or computer control system data prior to the work to ensure that the piping was not under pressure could have helped prevent this incident.

Source:CSB.gov

DOES YOUR LOW FLOW TRIP OF FIRED HEATERS TAKE CARE OF ALL PASSES?

 On August 19, 2022, at approximately 3:45 a.m., about 4,000 pounds of a hydrogen and hydrocarbon mixture was accidentally released into the firebox of a fired heater, where it ignited, creating a large fire at a refinery in Texas City, Texas. Estimated that the property damage from the incident was $10 million.

On the morning of the incident, the company restarted a fired heater that had been offline for approximately 12 hours due to a compressor shutdown caused by a malfunction of a pressure transmitter in the lube oil system. During the startup, it was essential to flow process feed through all four passes of the fired heater’s tube system. However, only two of the four passes in the tube system had sufficient flow through them when the burners were ignited. Although the minimum flow was eventually established in another tube pass, there was no flow through the fourth pass.
Company investigation of the incident found that without the fluid flowing through the fourth pass to remove heat, the tube’s metal wall temperature reached 1,500 degrees Fahrenheit (℉), which exceeded the design temperature limit. After the operations supervisor noticed the high temperature, field operators were sent to inspect the heater tubes. The field operators reported that some tubes were “glowing red hot,” and consequently they manually turned off two of the fired heater’s eight burners. The field operators then reduced the flow through the first three passes to help drive feed material into the fourth pass. Although operators reported hearing material flowing in the fourth pass, the meter indicated no flow. The operations team concluded that the flow meter was malfunctioning.
Less than an hour later, a convection section tube in the fourth pass ruptured due to short-term, overheating  releasing a flammable mixture of hydrogen and hydrocarbons into the firebox. Flames from the gas-fired burners ignited the mixture, resulting in a large fire.

During its investigation, the company discovered that the startup procedure for the fired heater, which required maintaining a steady flow through all four tube passes before lighting the burners, was not used. This procedure was “conditional,” however, and was only necessary if the firebox temperature had cooled below 400℉. At the time when the burners were lit, this temperature was slightly below 400℉.
Additionally, the company found that the fired heater lacked engineered safeguards to prevent the burners from being lit before establishing flow in each of the four passes. In response to the incident, the company modified its automated burner controls to help ensure that the flow rate through every pass exceeds a predetermined minimum flow rate before operators can ignite a burner.

Probable Cause
Based on the company investigation, the CSB determined that the probable cause of the incident was a ruptured fired heater tube from short-term overheating. Flames from the fired heater’s gas-fired burners ignited these flammable chemicals, resulting in the fire. The lack of automated safeguards that did not prevent the burners from being ignited before the minimum flow was established through each of the four tube passes contributed to the incident. Had the company had such automated safeguards in place, this incident likely could have been prevented.

Source:CSB.gov

ARE YOU CLEARING YOUR TANKS COMPLETELY AND ENSURING NO FLAMMABLE / TOXIC VAPOURS ARE PRESENT BEFORE HANDING OVER TO MAINTENANCE?

On July 29, 2022, at 7:45 a.m., an explosion and fire occurred at a facility in Mississippi. The explosion and subsequent fire fatally injured one employee and seriously injured five other employees 

The facility separates crude oil condensate (flammable liquid hydrocarbon) from salt water through a series of four tanks. After the crude oil condensate is recovered, the saltwater waste is pumped into a saltwater disposal well. Two of the tanks used in the disposal process were replaced with new tanks shortly before the incident occurred, but two tanks were not replaced.
The company's investigation found that although most of the liquid was removed from the two tanks that were not replaced, some salt water, residual hydrocarbon material, and air remained inside these tanks. At the time of the incident, seven employees were completing the tank replacement work, which included installing an elevated walkway between the tanks and finishing piping and structural connections. While welding piping between the two middle tanks, one of the employees opened a valve to the older tank that contained residual crude condensate material, likely releasing some hydrocarbon vapors into the new piping being welded. The flammable vapor ignited, and flames traveled back into the tank, resulting in an explosion and fire that ejected the top of the tank. In addition, the blast launched and forcefully propelled an adjacent tank approximately 80 feet into the woods 

As a result of the explosion and fire, six of the employees were transported and admitted to the hospital, where they received treatment for their burn injuries. One of these employees died at the hospital six days later.
The company's investigation found that no work permits were written for the welding work associated with the tank replacement task. An investigation by the federal Occupational Safety and Health Administration (OSHA) found that the tanks involved in the explosion had not been thoroughly cleaned, which allowed flammable material to remain near the welding activity at the time of the incident.

Probable Cause
Based on the company's and OSHA’s investigations, the CSB determined that the probable cause of the incident was the presence of flammable vapors near a welding activity being performed. Not thoroughly draining, cleaning, and purging the tanks to remove the flammable material before starting construction contributed to the incident. Had the tanks been thoroughly drained, cleaned, and purged prior to the commencement of construction, this incident likely could have been prevented.

Source:csb.gov

ARE YOUR PROCEDURES CLEAR AND WARN OF DANGERS?

On July 2, 2021, at approximately 9:15 p.m., approximately 700 pounds of a mixture of vapors, including chlorodifluoromethane (“R22”) and perfluoroisobutene (“PFIB”), were released a facility in Alabama . Exposure to the toxic mixture of vapors fatally injured two operators and seriously injured another Daikin operator.

A drying tower was being returned to service after it had been offline for maintenance. After the maintenance activity, this equipment contained air, and the procedure included steps to remove this air and replace it with R22. To accomplish this, the company used a two-step purge process. First, nitrogen was added to sweep out the air, and second, R22 was added to sweep out the nitrogen. The displaced vapors were released into the ambient air from an open valve about six feet above the ground for each step. The valve was aimed vertically downward, resulting in the vapors being released in a downward direction toward the area where the operators were working.
The procedure did not specify the source of the R22 material used in this purging operation. The R22 was taken from another process vessel that contained other chemicals, including PFIB. As operators performed this purging, PFIB was released into the ambient air from the open valve, exposing three operators to this toxic vapor. The operators did not immediately report any adverse effects from the exposure and went home at the end of their shift. Approximately two days later, two of the operators became ill and were admitted to the hospital. The next day, the third operator was hospitalized. Two of the operators later succumbed to their respiratory injuries. One operator died on August 10, 2021, and the second operator passed away on September 28, 2021.

After the incident, the comapny updated its procedure to warn that toxic vapors may be present and to require that its operators use supplied air respirators. In addition, the company now directs the purge vapors to an incinerator. The procedures were also updated to specify that only high-purity (non-toxic) R22 can be used in the purging procedure.

Probable Cause
Based on the company's investigation and an investigation by the federal Occupational Safety and Health Administration (OSHA), the CSB determined that the toxic PFIB vapors were likely released with R22, which was purged from equipment into the ambient air to remove nitrogen. The safety management systems, which allowed the discharging of R22, PFIB, and other byproducts into a work area, contributed to the severity of the incident. Had the company ensured that the release of these hazardous vapors was avoided or discharged to a safe location, the incident could have been prevented. 

Source:CSB.gov

ARE YOUR EMERGENCY SHUTDOWN PROCEDURES ADEQUATE TO PREVENT DAMAGE?

 On February 15, 2021, at 3:05 p.m., a hydrogen and hydrocarbon gas mixture was accidentally released into the firebox of a fired heater, where it ignited and exploded. It was estimated the incident resulted in $2.5 million in property damage.

The company's investigation found that the facility shut down multiple fired heaters when extreme cold weather from Winter Storm Uri caused several freeze-related operational issues. Due to emergency conditions that included utility losses and supplier-driven gas shortages, the company shut down its fired heaters without removing the solidified carbon deposits on the interior walls of the heater tubes (decoking).

The company's investigation revealed that further utility upsets caused the facility to stop all fuel gas supply and fully shut down the remaining fired heaters. During the shutdown, a valve between one of the ethylene unit’s fired heaters and downstream equipment remained open. The open valve allowed downstream flammable hydrogen and hydrocarbon gas to flow backward into the fired heater tubes. Approximately 30 minutes after this happened, a tube within the fired heater ruptured, allowing the flammable gas to enter the firebox. The gas accumulated, ignited, and exploded, causing extensive damage to the fired heater (Figure 2).

The company's investigation determined that the tube failure likely occurred because the fired heater tubes were shut down without decoking. Coke fouling can insulate the tube surface, resulting in local hotspots and increasing the risk of thermal shock and tube failure in fired heaters. These conditions stressed the tube’s walls when the metal cooled faster than the internal coke, breaking the tube. The company's investigation concluded that hot insulation inside the firebox likely ignited the gas (autoignition).

Probable Cause
Based on the company investigation, the CSB determined that the probable cause of the incident was a fired heater tube failure from thermal stress due to the rapid shutdown. When the tube broke, a hydrogen and hydrocarbon gas mixture from downstream equipment flowed into the firebox. Hot insulation within the firebox likely ignited the flammable gas, resulting in an explosion. Inadequate winterization of multiple valves, instruments, and control systems contributed to the incident.

Source: CSB.gov

HAVE YOU CONSIDERED FREEZING OF WATER IN INSTRUMENT AIR HEADERS DURING LOW AMBIENT WEATHER CONDITIONS?

 On February 15, 2021, at 9:53 p.m., a hydrogen and hydrocarbon gas mixture was accidentally released into the firebox of a fired heater, where it ignited, creating a fire at a facility in Texas. The estimated property damage from the incident was $5.8 million.

The company investigation determined that freeze-related operational issues due to extreme cold weather from Winter Storm Uri caused the facility’s boiler units to shut down. This shutdown decreased the supply of steam and water to an ethylene unit at the facility. A safety system automatically shut the fired heater down due to insufficient steam and water flow. Although the automatic valves closed to prevent feed from entering the tubes, the fired heater’s fuel gas isolation valve failed to close as intended. This failure allowed the burners to continue operating. Without any flow through the tubes to remove heat from their walls, the tubes in the fired heater reached excessively high temperatures. Some tubes ruptured, likely due to short-term overheating, but a metallurgical analysis was not performed to confirm the cause of the tube failures. When the tubes ruptured, hydrocarbons downstream from the fired heater were released through the broken tubes and ignited by the burner flames inside the firebox, causing a fire.

During post-incident testing by the company in temperatures above freezing, the fuel gas isolation valve successfully closed as designed. The company's investigation concluded that the fuel gas isolation valve did not close because water in the instrument air supply had frozen or ice formed on the external actuator components (related to inadequate winterization), preventing the isolation valve from closing.
Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was the rupture of fired heater tubes from short-term overheating. When the tubes were broken, a hydrogen and hydrocarbon gas mixture flowed from downstream equipment into the firebox. Flames from the burners ignited the flammable materials, resulting in the fire. Inadequate winterization of flow control equipment contributed to the incident.

HAVE YOU IDENTIFIED ALL POSSIBLE SOURCES OF CORROSION?

On October 1, 2020, at approximately 9:00 a.m., approximately 554 pounds of chlorine gas were accidentally released at a facility in Louisiana. Exposure to the toxic chlorine vapors seriously injured one employee.

At the time of the incident, four workers (two employees and two contractors) were trying to stop a chlorine leak (described by as a fugitive emission) from a drain valve in the company’s methyl diisocyanate production plant. Because a chlorine leak was detected, the company assumed that at least one of the drain valve’s connections in its flanges or bonnet was loose.
The four workers had a safe work permit to retighten the bolts using hand tools. However, the leak persisted after the bolts were retightened by hand. One of the contractors then tried to retighten the bolts using an impact wrench, a power tool designed to tighten and loosen bolts with short bursts of high torque. The vibrations from the impact wrench caused the connections on the drain valve’s bonnet to fail catastrophically, forcefully disconnecting the top half of the drain valve (closing element, stem, and handle) from the bottom half (body and seat) and releasing the toxic chlorine vapors.
The workers were wearing supplied air respirators to perform the job. After the chlorine release, they evacuated the area. However, one employee did not switch to the “escape bottle” for their respirator before detaching the respirator from the stationary air supply source during the evacuation. The subsequent lack of supplied airflow in the respirator caused the employee to remove their respirator mask during the evacuation, resulting in the employee being exposed to the toxic chlorine vapors. The employee was transported and admitted to a hospital for medical treatment.
The company's investigation found that the drain valve was severely corroded. Over time, chlorine being released from the drain valve had reacted with condensed water that had accumulated in the piping system’s insulation blanket, creating hydrochloric acid that had corroded the valve and deteriorated the bolts in the valve’s bonnet. After the incident, the company discovered that three other valves were similarly corroded.

The investigation also revealed that one of the contractors tried to use their stop work authority after seeing the dilapidated valve. The contractor brought concerns to one of the employees. While the  employee went to get a supervisor’s opinion, there was a miscommunication between the two parties about whether or not to continue working on the corroded valve. As a result, the work continued, ultimately leading to the chlorine gas release.

Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was the catastrophic failure of corroded bolts in the drain valve’s bonnet. The corrosion was caused by prolonged exposure to hydrochloric acid, created by the reaction between chlorine and condensed water.
Contributing to the incident was the company's mechanical integrity program. Had the company  inspected the valve before authorizing this job, the extent of the corrosion could have been identified, and a shutdown could have been initiated to replace the drain valve instead of attempts to repair it. Contributing to the severity of the incident was the company's respiratory protection program, which did not ensure its workers could effectively transition to the escape bottle during an emergency. Had the company effectively trained its workers to switch to their escape bottles during an emergency, the employee should have not been exposed to the chlorine.

Source: CSB.gov

DISTILLATION TOWER COLLAPSE DUE TO INTERNAL FIRE

On September 5, 2023, at 11:50 a.m., a distillation tower (“Tower”) collapsed (Figure 1) at a Petrochemical in Texas. The collapse was the result of a fire inside the distillation tower. The incident resulted in approximately $194 million in property damage.

A few weeks before the incident, the company shut down its Pyrolysis Gasoline unit, including its extractive Tower. The company followed its procedure to remove solvent and hydrocarbons from within the Tower to prepare for maintenance work. On the day of the incident, a maintenance crew began opening manways to prepare the Tower for entry. At 9:30 a.m., temperatures with the Tower’s stainless steel structured packing beds began to rise. The company sounded an emergency alarm at 10:44 a.m. after smoke and flames showed a fire within the Tower. Personnel were evacuated after adding nitrogen and trying to stop air from entering the Tower. At 11:53 a.m., the Tower folded over (collapsed).
The company investigation found that the Tower fire resulted from a chain of undesired reactions. About a month before the unit shut down, equipment leaks in another area of the process allowed water to enter the extractive distillation unit, leading to internal corrosion that removed iron from the metal walls. This iron formed iron sulfide (a pyrophoric material) from hydrogen sulfide that is usually present in the process equipment. When the Tower’s manways were opened, oxygen (air) entered the Tower, starting an exothermic iron sulfide oxidation reaction. The company concluded that the heat from this iron sulfide oxidation reaction resulted in localized heating (1,300 to 1,800 degrees Fahrenheit) within the structured packing that weakened the Tower’s walls and ultimately caused the Tower to collapse.
In addition, The company’s investigation found that a 2016 incident had revealed the potential for iron sulfide to accumulate within the Tower. The investigation team determined that this knowledge had not been effectively transferred to the existing site personnel. Had the site’s operations team known about the potential for iron sulfide within the Tower, changes to the procedure to remove solvent and hydrocarbon could have been made to mitigate the heating from the iron sulfide oxidation.
During the incident, approximately 160 pounds of sulfur dioxide and an unknown amount of other reaction and combustion products were accidentally released.
Probable Cause
Based on The company’s investigation, the CSB determined that the probable cause of the fire was smoldering iron sulfide oxidation within the structured packing of the Tower. Contributing to the incident was that the company did not effectively maintain its knowledge from its 2016 incident finding that iron sulfide could accumulate within the Tower.

Source: CSB.gov

TANK OVERPRESSURE INCIDENT

On June 22, 2023, at about 9:10 p.m., a 5,200-gallon polyethylene storage tank (“tank”) ruptured at a facility in North Carolina. The rupture fatally injured one employee.
At the time of the incident, the tank needed to be refilled with aluminum chloride; however, sulfuric acid was added instead. Approximately 80 gallons of 93 percent sulfuric acid were added to the 60 gallons of aluminum chloride remaining in the tank, resulting in a reaction that caused the tank to rupture. The tank rupture fatally injured the employee who was refilling the aluminum chloride tank.
The company's investigation appeared to focus on the incorrect reaction rather than a reaction scenario consistent with the available evidence. Its research materials pointed to the reaction between sulfuric acid and aluminum metal that generated hydrogen gas. The company concluded that the hydrogen gas was released at its autoignition temperature (over 1,000 degrees Fahrenheit (°F)) and ignited, triggering an explosion. Post-incident photographs of the damaged tank do not appear to support a scenario where the internal tank temperature reached 1,000 °F, however. The melting temperature of the polyethylene is approximately 260 °F. Therefore, the company’s reaction scenario appears inconsistent with the available evidence.
The CSB concluded that the reaction most likely generated hydrogen chloride vapors. The more likely scenario was that the reaction between aluminum chloride and sulfuric acid produced enough hydrogen
chloride vapor to increase the pressure within the polyethylene tank, likely resulting in an overpressure that separated the tank’s body from its base.
The CSB estimated that approximately 130 pounds of hydrogen chloride vapors were accidentally released.
Probable Cause
Based on the factual information from the company's investigation, the CSB determined that the probable cause of the overpressure was the increase in the tank’s internal pressure resulting from the hydrogen chloride vapors created by the reaction between sulfuric acid and aluminum chloride.

Source:CSB.gov

A SELF ACCELERATING DECOMPOSITION REACTION KILLS AN OPERATOR

On May 4, 2023, at about 12:40 a.m., a pressure Nutsche filter vessel (“vessel”) exploded at a facility in  Massachusetts. The explosion and fire fatally injured one operator and caused approximately $48 million in loss from property damage, which led to the permanent closure of the facility.

At the time of the incident, the plant was producing a substance called Dekon 139 (“Dekon”). The Dekon had already been synthesized, and excess liquid from the production process had been removed from the solid product (“cake”) within the nitrogen-inerted vessel. The plant used an agitator to smooth the cake and remove lumps that formed during drying to remove the liquid from the cake.                                                                                                                                                                            In post-incident testing, the plant determined that Dekon could undergo exothermic, self-accelerating decomposition when heated to 280 degrees Fahrenheit. The plant learned that Dekon decomposition releases flammable gases, including hydrogen, methane, and carbon monoxide.
In its incident investigation, the plant determined that leading up to the incident, the agitator had loosened and was rubbing a plate at the bottom of the filter dryer vessel, generating heat from friction. The friction likely caused an area of high temperature (“hot spot”) in the Dekon, which likely reached the temperature
necessary for the Dekon to begin decomposition. The decomposition reaction released energy, which increased the temperature of the material in the vessel and caused more Dekon to decompose.                                                                                                                                
The gases produced by the reaction rapidly increased the pressure within the vessel, causing the vessel’s discharge door to open. The released flammable materials (gas and Dekon dust) mixed with atmospheric oxygen and ignited, causing an initial weak explosion. Shortly after that, the vessel’s rupture disc opened, and a second larger explosion occurred when the vessel failed.
One operator was unable to escape the area and was fatally injured.
The CSB estimated that approximately 600 pounds of Dekon decomposed into flammable gases that were consumed during the incident.
Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the explosion and fire was a self-accelerating decomposition reaction of Dekon, which produced flammable gases and released combustible Dekon dust that ignited upon release. Contributing to the incident was the company's incomplete knowledge of the hazards associated with Dekon, including its ability to undergo a self-accelerating decomposition reaction capable of rupturing the reaction vessel.

Source:CSB.gov

Watch "Process Alarm Systems Updates to EEMUA 191 by Andy Brazier" on YouTube

 Watch "Process Alarm Systems Updates to EEMUA 191 by Andy Brazier" on YouTube

 https://youtu.be/xh62GMQ53u0?feature=shared

INCOMPATIBLE CHEMICALS CAUSE H2S RELEASE

 On March 29, 2023, at approximately 5:05 p.m., toxic hydrogen sulfide gas was accidentally released at a paper mill in Kentucky. Exposure to the hydrogen sulfide gas seriously injured one operator and injured two other operators.
At the time of the incident, three operators were tasked with circulating an acid-cleaning solution through process equipment to remove the buildup of solids impairing its performance. This task required an operator to stand directly over a tank and pour solid sulfamic acid powder into its opening.
When these operators added the sulfamic acid powder, the tank should have contained water, but a valve had been left open. This allowed a “weak wash” process stream to enter the tank before the operators added the solid sulfamic acid. The weak wash contained sodium sulfide, which reacted with the sulfamic acid, generating the toxic hydrogen sulfide gas.
Operator 1, who was standing directly over the tank opening (Figure 1), lost consciousness from exposure to the hydrogen sulfide gas that evolved from the tank. Operator 3 was able to call for help over the plant radio system but lost consciousness soon after. Operator 2 was seriously injured after losing consciousness (while trying to help Operator 1), falling to the floor, rolling through a guardrail system, and falling about 11 feet to a lower area of the structure.
Two other Domtar employees heard the distress call and entered the room to help the operators. All three operators regained consciousness. Operator 1 and Operator 3 were able to walk outside without assistance. Emergency responders transported Operator 2 to a hospital for treatment.
The company reported that about 25 pounds of hydrogen sulfide were released.

Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the hydrogen sulfide release was the reaction between the added sulfamic acid and the sodium sulfide in the tank. The company's procedure procedures did not indicate that the weak wash valve should be closed during normal operation, which contributed to the incident. Had the weak wash valve remained closed (or more robustly isolated), sodium sulfide could have been kept out of the tank, preventing the reaction that generated the toxic hydrogen sulfide.

Source:CSB.gov

"Travel Stops on Spring Supports: What Engineers Need to Know" by Piping Technology and Products

The June 2025 process safety beacon talks about an incident that I had experienced with a locked spring hanger. Read the beacon in this link https://ccps.aiche.org/resources/process-safety-beacon/archives/2025/june/english

Piping Technology and products have published a safety alert explaining  "

"Travel Stops on Spring Supports: What Engineers Need to Know"

Read it in this link

https://pipingtech.com/resources/technical-bulletins/safety-alert-installation-spring-supports/

 

 

A FIRE WATER HOSE CAUSES A PUMP TO CRACK AND INJURE A EMPLOYEE

On February 24, 2023, at 9:20 a.m., an accidental release of approximately two gallons of a sodium hydroxide and water solution (“caustic solution”) seriously injured an employee at a facility in South Carolina.
A new pump for unloading caustic solutions from tank trucks was installed at the facility the day before the incident. On the day of the incident, the company used the new pump for the first time. Employees turned on the pump to begin transferring the caustic solution from a tank truck, but the pump failed to move fluid and leaked. The employees planned to disassemble the pump to identify the operational problem.
Before disassembling the pump, it was decided to flush it out with water from a fire hose. This action was taken to prevent employees from getting the caustic solution on their hands when the pump was disassembled. An employee connected a fire hose to the pump and partially opened the valve. The pump could not handle the pressure supplied by the firewater, and the plastic pump casing cracked. Caustic solution and water sprayed out of the pump, seriously injuring one employee.

After the incident, the company modified its caustic unloading system, eliminating the need for an unloading pump.
Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was the overpressure of a pump casing after pressurized firewater was introduced to the pump.

Source:CSB.gov

INCIDENT DUE TO LONE WORKING WITHOUT ENGINEERING SAFEGUARDS

During the morning of February 24, 2023, an unknown amount of hydrocarbons and hydrogen sulfide were accidentally released, fatally injuring an employee inside an enclosed building at an oil and gas facility in Dakota. The hydrocarbons and hydrogen sulfide displaced the oxygen in the building, and the employee asphyxiated in the oxygen-deficient atmosphere.

The employee was considered a “lone worker” who operated multiple oil and gas facilities in the local area. Some of the oil and gas equipment was housed inside enclosed, insulated buildings, allowing operators to work in a climate-controlled environment. At the time of the event, it was negative 26 °F outside, and the interior of the building where the incident occurred (approximately 8 feet tall and 90 square feet) was about 65 °F.
A pump inside the building was not operating as designed, causing an adjacent vessel to begin overfilling. To prevent the vessel overfill from causing the facility to shut down, the employee began manually draining the vessel and another nearby vessel, both of which were housed inside the building. To drain the vessel, the employee connected a temporary hose to it and drained its liquid, mostly water and hydrocarbons, into a bucket inside the building. The employee then left the building temporarily to conduct operations at other locations in the facility. During this time, the drained hydrocarbons vaporized inside the enclosed building and displaced oxygen. About twenty minutes later, the employee returned to the insulated building and may have accidentally knocked over the bucket of drained liquid. Additional hydrocarbons and hydrogen sulfide likely vaporized, further displacing the oxygen inside the building. The employee breathed in the oxygen-depleted atmosphere and asphyxiated.
The building where the draining occurred did not have detectors installed to monitor for hazardous gases, and it was not ventilated. The employee had a personal gas detection monitor, but it was turned off and in his truck. No company procedure was in place that provided instructions for safely draining liquids from vessels inside buildings.
After the incident, the company evaluated adding additional engineering controls (for example, hazardous gas detection and alarms, forced ventilation) to its enclosed buildings, developed a written procedure requiring that process fluids be drained outside of buildings, and enhanced training and supervisor verification requirements regarding the use of personal gas monitors.
Probable Cause
Based on the company's investigation, the OSHA inspection, and the local Sheriff’s Office investigation, the CSB determined that the probable cause of the incident was the displacement of oxygen inside an enclosed building after an operator drained process liquid into a bucket and the hydrocarbon and hydrogen sulfide components vaporized. Contributing to the incident was the absence of company procedures detailing instructions for safely draining liquids from vessels located inside buildings. Contributing to the severity of the incident was the lack of engineered safeguards (such as installed detectors, alarms, and ventilation) to control or alert of a hazardous atmosphere and an unsuccessful system for ensuring employees wear personal gas monitors.

Source:CSB.gov

H2S RELEASE DUE TO SULFIDATION CORROSION

On April 8, 2023, at about 7:45 a.m., hydrogen sulfide and sulfur dioxide were released from the sulfur recovery unit at the a Refinery in Minnesota . This event resulted in $2.235 million in property damage.

The accidental release resulted from a ruptured tube within the waste heat boiler of the sulfur recovery reaction furnace. The tube rupture was caused by a damage mechanism known as sulfidation corrosion (also known as high-temperature sulfidic corrosion). Under certain temperature conditions, sulfidation corrosion causes thinning in iron-containing materials over time due to a reaction between sulfur compounds and iron.

The company investigation also found fouling (hydrocarbon solids), which had formed on the outside of some tube wall surfaces, resulted in higher tube wall temperatures and areas of increased metal loss from sulfidation corrosion. The investigation also found that the hydrocarbons were in the boiler feed water. This indicates that the boiler feed water was not being effectively monitored, which allowed the hydrocarbon contamination to remain undetected.

The company reported that approximately 68 pounds of hydrogen sulfide and 999 pounds of sulfur dioxide were released.The company now monitors and controls boiler feedwater quality with in-line analyzers. The analyzers continuously sample boiler feedwater and strip any hydrocarbons from the sample. A carrier air then sweeps the hydrocarbons to a metal-oxide sensor for quantitative analysis. The in-line sample results provide the opportunity to evaluate hydrocarbon presence in near real-time. This allows for identification when boiler feedwater does not achieve American Society of Mechanical Engineers (“ASME”) recommendations based on hydrocarbon measurement and implementation of prompt corrective measures as necessary.
Probable Cause
Based on the company investigation, the CSB determined that the probable cause of the accidental hydrogen sulfide and sulfur dioxide release was a tube rupture in the waste heat boiler. The tube had thinned over time from sulfidation corrosion. Contributing to this event was hydrocarbon contamination in the boiler feed water that was not being effectively monitored and controlled, resulting in localized tube fouling that led to increased tube wall temperatures and thinning from the sulfidation corrosion damage mechanism.

Source:CSB.gov

POINTING AND CALLING - REDUCING HUMAN ERROR DUE TO AUTOMATION BIAS

Source: Google

The pointing and calling method, known as "Shisa Kanko" in Japanese (指差喚呼), is a safety procedure used extensively in Japan, particularly in the railway system, to minimize errors and enhance focus. It involves physically pointing at a relevant indicator or control while verbally announcing its status. This dual action engages both visual and auditory senses, reinforcing attention and reducing the likelihood of mistakes.

Core Concept: Operators point at specific indicators (like signals, gauges, or controls) and verbally announce what they are observing or doing. 

 Example:A train driver might point at a signal displaying a green light and say, "Signal is green, proceeding." 
This method has been shown to significantly reduce errors and accidents in various industries, especially in the Japanese railway system, where it's been a key factor in maintaining high safety standards.
Widespread Use: While originating in the railway sector, pointing and calling is now used in many Japanese industries, including manufacturing, construction, and even in some office settings. 
Cognitive Impact: Studies suggest that pointing and calling activates different parts of the brain compared to simply looking or thinking about a task, further enhancing its effectiveness in preventing errors. 
 

Watch "Pointing and Calling – A simple way to reduce automation bias" on YouTube
https://youtu.be/UusWoWPZLNQ?feature=shared 

Answer from Perpexity Pro for my question - Number of Chemical Plant Accidents in India (2015–2025)

 Answer from Perpexity Pro for my question - Number of Chemical Plant Accidents in India (2015–2025)

"Major Chemical Accidents: Over the last 10 years, India has reported approximately 130 major accidents in chemical plants and industries.

Deaths and Injuries: These incidents led to at least 259 deaths and 563 serious injuries according to the National Disaster Management Authority (NDMA).

Monthly Average: In the three years prior to 2020 alone, there were more than four major chemical accidents each month in chemical manufacturing facilities—indicating ongoing risk and persistent safety challenges.

Increasing Trend: The frequency of gas and chemical leakage incidents has notably increased, with the number of registered accidents rising from 13 in 2013 to 30 in 2023, showing that the rate of accidents is climbing.

States Most Affected: Gujarat has repeatedly been the state with the highest number of reported incidents, for example, accounting for 24 of the 30 chemical leakage accidents nationwide in 2023.

Key Facts
Most commonly reported accidents are major fires, explosions, and toxic releases.

Fatalities and injuries figures are likely underestimates, as some incidents are not registered or fully documented.

SMEs and densely industrialized states remain particularly vulnerable.

Summary Table
Period last 10 years
Major Accidents 130
Deaths 259
Serious Injuries 563

*Approximate values, as per NDMA and national reporting.

The continued recurrence of chemical plant accidents in India highlights the need for improved process safety management and regulatory enforcement, particularly in rapidly industrializing regions and among small and medium-sized enterprises."

YOU CANNOT IDENTIFY A PROCESS HAZARD IN HAZOP IF YOU ARE NOT AWARE ABOUT IT!

On January 31, 2023, at 6:40 a.m., an accidental release of high-pressure carbon dioxide (CO2) occurred when a vessel overpressured and catastrophically ruptured at a CO2 gas plant in Texas. Vessel fragments propelled up to 1,200 feet away and heavily damaged a control room (Figure 1). Kinder Morgan estimated the property damage to be over $14 million.

The incident occurred in the site’s CO2 compression system. Upstream of each compressor was a vessel called a scrubber that removed liquid from the CO2 feed stream. Removing liquid from compressor feed streams is critical to preventing compressor damage.
On one of the high-pressure compressor system scrubbers, a liquid level control valve (called a “dump valve”) became stuck in the open position, which was common at the site during cold weather. The outside temperature at the time was 22 degrees Fahrenheit (°F). The liquid drained out of the high-pressure scrubber through the stuck-open valve, and then high-pressure CO2 gas also started flowing out through the stuck-open valve. The high-pressure gas was released into the low-pressure drain system, and as it did, the CO2 became cold—as low as negative 30 °F (due to the Joule-Thompson effect).

The cold CO2 caused ice or hydrate to form in a drain system vessel’s outlet piping, including the piping to its emergency pressure relief valve. When this happened, the high-pressure CO2 could not vent through the pressure relief valve. The pressure in the drain system vessel continued to build until it reached about 550–700 pounds per square inch gauge (psig) and catastrophically ruptured. The vessel fractured in a brittle mode, producing fragments that flew up to 1,200 feet away.
The ruptured drain system vessel, which was made of carbon steel and measured 15 feet long by 6 feet wide, was rated to a maximum pressure of 125 psig at 650 °F. The blocked pressure relief valve had a set pressure of 15 psig. The scrubbers that drained liquid to the drain system operated at pressures ranging from 450-1,000 psig.
The failed vessel did not have instrumentation installed to allow operators to monitor conditions such as pressure, temperature, or level, and the scrubber liquid level and dump valve position were not recorded. The system’s lack of instrumentation prevented operations personnel from identifying the abnormal operating condition and taking corrective action.
In two previous process hazard analysis (PHA) reviews, the company had identified the potential for CO2 gas to blow through a scrubber dump valve, but this scenario was identified as an operational problem, not a safety problem. The PHAs did not identify the potential for ice or hydrate formation in the drain system due to a stuck-open dump valve. The PHAs also did not include a full review of the downstream closed drain system, as the closed drain system was viewed as a low-pressure utility system with low safety risk.
The company's investigation concluded that the incident resulted from the thermodynamic properties and system pressures not being sufficiently accounted for, resulting in inadequate vessel and piping design, inadequate overpressure protection, and inadequate instrumentation. The investigation recommended, among other corrective action items, that the site create an engineering design standard that addresses hazards associated with introducing high-pressure fluids into drain systems.
The company reported that 5.6 million pounds of carbon dioxide were released. In addition, the company reported that natural gas (111,000 pounds), hydrogen sulfide (2,000 pounds), carbon monoxide (1,400 pounds), sulfur dioxide (1,200 pounds), and nitrogen oxides (NOx) (260 pounds) were also released.
Probable Cause
Based on the company investigation, the CSB determined that the probable cause of the incident was the overpressure of a drain system vessel after a scrubber dump valve became stuck in the open position. Ice or hydrate formed in the vessel outlet piping, blocking the relief path. Inadequate vessel and drain system design and the lack of needed equipment instrumentation contributed to the incident.

Source:CSB.gov