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