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