ARE YOUR FLANGE TIGHTENING TORQUES PROPERLY SET?

While re-starting an ammonia production unit in a chemical plant following a technical breakdown that lasted one hour and 30 minutes, a synthesis gas leak (50% hydrogen, methane, nitrogen and 17% ammonia) ignited on a flange (O-ring joint) located just after the synthesis reactor. The operator triggered the emergency shutdown after the unit’s alarms were triggered, isolating and depressurising the synthesis cycle. Steam was sprayed on to the leak using mobile fire nozzles to extinguish the fire that was brought under control 55 minutes following its start. Material damage was estimated at 60 K euro The blaze did not damage the reactor that was protected by a deflector. Operating losses stood at 300 k euro. 

The tightening torques of the bolt on flange where the leak occurred is responsible for the accident: they were not adapted to the exceptional conditions prevailing during the accident (significant temperature difference between the bolt and the flange resulting from the abrupt temperature variation due to the short technical breakdown.) The implemented corrective actions involved redefining the tightening torques, improving the tightness of the drip collar on the flanges (defective at the time of the accident), designing a nitrogen injection system in drips collars and installing a steam injection crown to protect the bottom of the synthesis reactor.

Source:Aria database

ARE YOUR INTERLOCKS TESTED?

A fire broke out in a chemical warehouse that was inactive at the time. The flames had spread through the area used to store acids, bases and peroxides and included 28 storage tanks. This area is separate from the flammable products area. The site's Internal emergency Plan (IOP) was initiated. 

Six tanks containing hydrochloric acid, potash, flocculant, alkaline solutions and soda were destroyed, and the flames damaged five others. Overheating of a heating element in an empty soda tank over several hours caused the incident, as the product low-level detector had not switched off its power supply. The energy produced melted and then ignited the tank filled with HDPE (high-density polyethene). The material of which tank is made of then also fuelled the fire. The operator implemented the following preventive measures: - no heating device on product storage tanks not requiring it; - preference is given to steel or stainless steel tanks with electric or hot water heating; - the new plastic tanks are heated by hot water only; - the heating power must not allow a tank to ignite, - the reliability of the controller used to regulate the tank heating systems must be improved.

Source:Aria database

ARE YOU INSPECTING ALL VULNERABLE COMPONENTS OF PIPING AS PER STANDARDS?

At 11:15 pm, high-pressure steam pipe elbow at 120 bar and 520°C connected to catalytic reforming equipment burst. The elbow and pipe , a 40-kg block of steel, was projected longitudinally. Inside the shop area, a walkway was ripped off its supports damaging an access ladder. It then flew over an ammonium nitrate conveyor belt only to land 230 m away in a parking zone for tanker cars full of ammonia awaiting shipment, which on that day happened to be empty. The steam tore apart the asbestos cement cladding on the wall located 20 m from the original rupture and escaped into the atmosphere with a load noise. 

The two employees present in the unit at the time shut down production operations and cooled the steam reformer with nitrogen. 

A metallurgical assessment of the elbow indicated that slow creep had initiated on the outer skin, which combined with flow into the material layer was the cause of pipe rupture. This hypothesis relied on the detection of oxidised, yet non-deformed, pipe openings in the presence of intergranular microcracks on both the pipe and its elbow. The origin of this creep was explained by the metallurgical composition of the elbow, i.e. ordinary carbon steel containing no alloys and not adapted to temperatures above 425°C. The pipeline was made of a slightly-alloyed P22 type steel, which was more resistant to creep and compliant with the original specifications defined 32 years prior for both material elements. 

Inspections carried out at the time on the elbow did not detect any noncompliance of the steel, given that non-destructive technology had not yet come of age. This creep might have been accelerated as a result of heat treatment performed at 700°C during equipment installation, once the assembly had been welded. Periodic inspections dedicated to pressurised equipment on the damaged pipe were only recorded into the log 25 years after service start-up, at the time of applying for facility recertification. The initial recertification was rendered official without any underlying structural documentation (misplaced), and subsequent inspections never focused on the section of pipe that would burst.

Source: Aria database

CONFUSION DURING A MAJOR LOPC CAUSES WRONG ACTION TO BE TAKEN

In a petrochemical complex, an ethylene (a highly flammable gas) compressor was in stable operation when a sudden drop in pressure occurred at 5:33 p.m., accompanied by a loud noise. The gas detectors in the zone became saturated, and a 2nd level alarm was triggered in the unit’s control room, as well as in the control room controlling the nearby compressor and at the safety station. The compressor began to vibrate. Its motor stopped but not its ethylene supply.

Confusion over which compressor was leaking
Not knowing which compressor was causing the leak, the shift crew of compressor No. 1 contacted the crew in charge of compressor No. 2. The latter crew persuaded them it was compressor No. 2 that was to blame. Crew No. 1 left their control room to help them. The alarms and parameters indicating the malfunction of compressor No. 1 (pressure drop) were not taken into account since the control room had been deserted.

The two shift crews, joined by the internal fire brigades, approached the area of the accident but were unable to enter due to the deafening noise. They encountered a flammable cloud of ethylene measuring 4 m high x 100 m, with visible droplets. The firefighters protected the nearby units with water curtains. Around 5:45 p.m., the shift leader 1 consulted with the shift leader in charge of the neighbouring unit. A leak on the ethylene supply network was suspected. Two operators, equipped with hearing protection, moved through the cloud, protected by a water curtain, to reach the network’s manual shut-off valves. They were able to close the valves manually, ending the leak. The cloud rapidly dispersed. The operators returned to the control room and closed the local supply valve of compressor 1. 8 t of ethylene (354 kg of flammable mass) was released in 21 minutes.

ROOT CAUSE: Valve ejection due to incorrect tightening and a non-compliant seal
The hatch and the valve porthole of the second stage of compressor 1 were found 6 m away. One stud from the hatch was severed (sudden brittle-type rupture), while the other five studs remained in place, three of which were missing their nuts and exhibited torn threads. These studs are compliant but had never been replaced since the compressor was commissioned 16 years ago. An expert assessment showed that the valve’s copper seal was not annealed at the time of its installation, contrary to procedure and the other seals on the equipment. It was therefore not as flexible and less able to absorb stresses. This defect, combined with a bolt tightening error on the verge of plastic deformation, led to fluttering in the stack and its rupture.

If the emergency stop had been activated, the leak could have been stopped more quickly as it shuts down both the motor and the ethylene supply. The operators believed that the motor shut-down because of vibration was sufficient. After the accident, the compressor was equipped with an emergency stop triggered by gas detection. However, the manual emergency stop remains in operation should this detection system fail.

Source: Aria database

DO YOU HAVE CHECKS ON YOUR PREFERRED VENDOR WHEN IT OUTSOURCES COMPONENTS?

On February 22, 2024, at 4:20 a.m., a valve leaked hot liquid hydrocarbon, which ignited, resulting in a fire in refinery in Louisiana . It was estimated  that the fire caused $1.2 million in property damage.

On the morning of the incident, unit operators saw a decrease in the crude unit’s vacuum tower bottoms (VTB) flow. Field operators then found a fire near the flow control valve. Emergency responders extinguished the fire within minutes. It was reported that approximately 12,000 pounds of VTB material were released.
The comapny's investigation found that a recently installed 4-inch stainless steel globe valve in the VTB flow control station bypass piping had leaked at its pressure-retaining cover (bonnet). The valve had a Teflon (PTFE) bonnet gasket and Teflon packing, which were limited to 450 degrees Fahrenheit (℉), and were incompatible with the 650℉ VTB material. The valve was ordered in August 2023 and installed during a unit outage on February 16, 2024, six days before the incident.
The valve was equipped with two tags that provided conflicting information. When the company ordered the valve from its preferred vendor, the order included the refinery’s valve number, which specified a valve that met the process requirements by using graphite for the bonnet gasket and packing material. Teflon was not an acceptable material for this application.

The company's preferred vendor did not have this valve in its inventory, so it procured the valve from a third-party supplier. The manufacturer’s tag attached to the valve correctly indicated that it was equipped with Teflon components and stated that the valve’s maximum operating temperature was 450°F. However, the third-party supplier wired an additional tag stamped with the refinery’s valve number to the valve, incorrectly identifying the valve as having graphite components. Refinery personnel accepted and installed the valve based on the order and receipt documentation, along with the valve’s size, flange rating, and the refinery valve number.
Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was the installation of a valve with Teflon components that could not withstand the process temperature. The company could have prevented the incident by confirming that the manufacturer’s tag indicated that the valve was assembled with the proper components and that the valve’s design temperature was compatible with the vacuum tower bottoms temperature. Contributing to the incident was the third-party supplier’s tag, which incorrectly identified the valve as having graphite components

Source:CSB.gov 

WRONG MATERIALS OF CONSTRUCTION OF FLANGE BOLTS CAUSES AN INCIDENT

A spill of nitric acid occurred from a nitric acid absorber tower when a flange failed. An operator noticed a small leak from the flange bolts and proceeded to climb the tower towards the top isolating valve. At this time the flange bolts failed and sprayed acid into the absorber tower bund. The operator climbed to the next level and shut down the operation of the plant. Once the acid level had dropped to below the level of the flange, gaseous oxides of nitrogen were released. The operator then used water spray to reduce the impact of gas and acid mist. Industrial neighbours were notified of the release and the acid in the bund was neutralised with lime and sand, and later used in another onsite manufacturing process.
Key learning points
The investigation revealed that the bolts in the flange were mild steel bolts, which were not appropriate for use in nitric acid applications. These bolts were found to be corroded, which eventually led to the leak. As a follow-up, the company reviewed all the bolts used in the process. Five other flanges were identified as having mild steel bolts rather than stainless steel bolts. It was found that these bolts had not been replaced since plant commissioning. All inappropriate bolts were immediately replaced with stainless steel bolts suitable for acid applications. To prevent a recurrence the company implemented quality control procedures and inspection test plans for new projects and maintenance work. Verify that components, such as flanges and gaskets comply with the material specifications.

 Source:IChemE 

 

ACID ATTACK ON CONCRETE CAUSES AN INCIDENT

On 4 February, 2005, a storage tank containing 16,300 tons of 96 % sulphuric acid ruptured. The content of the reservoir spilled out into the bund and then the dock. The remaining 2,000 tons of acid in the bund came into contact with salt water that created an exothermic reaction, which produced an acid cloud consisting of hydrogen chloride. The vapour cloud drifted along the coastline and mostly over the sea. No one was affected by the event.
Key learning points
The incident was caused by a leak in the cooling water supply pipe passing under the tank farm. The leak undermined the ground under the foundations of a tank which then ruptured because of the uneven weight distribution resulting in the sudden release of the acid. The bund was filled with salt water when the rupture occurred and that caused the formation of hydrochloric acid. The pipe was made of concrete and came into use in the early 1960s. The only damage noted to the pipe was a leak at the pumping station in 1999. The inspection of the failed pipe following the incident detected little or no internal corrosion, but heavy external corrosion to the concrete. In certain parts of the pipe the concrete has corroded so severely that the reinforcing steel had also been exposed. It suggests that the corrosion was as a result of an acid attack on the concrete. According to the standards, a strong acid attack on concrete occurs if the pH level in surrounding water is < 5.5 and a very strong attack if the pH level is < 4.5. The company drew the conclusion that the pH level measured as 4 in the shallow groundwater in 1989 entailed risks for strong acid attack on the concrete. However, there was no risk assessment conducted.

Source:IChemE 

 

IMPORTANCE OF ASSET INTEGRITY AND SUBJECT MATTER EXPERTS

 On 6 August, 2012, a catastrophic loss of containment occurred on an 8-inch diameter piping associated with the gas-oil side-draw on an atmospheric crude distillation column in a refinery. The pipe ruptured, releasing flammable hydrocarbon process fluid to the environment. The flammable liquid partially vaporized into a large vapor cloud engulfing nineteen employees. After two minutes the flammable portion of the vapor cloud ignited. All of the employees escaped, narrowly avoiding serious injury.

Key learning points

The underlying cause of the pipe rupture appears to be poor maintenance procedure in regard to mechanical integrity. Subsequent testing determined that the rupture was due to pipe wall thinning caused by sulphidation corrosion. In fact, over a period of nearly 35 years, the 52-inch long piping component had lost on average, 90 percent of its original wall thickness in the area near the rupture. Although the company employed experts in sulphidation corrosion, they were not consulted on any key decisions associated with potential sulphidation risk of the crude distillation unit. The crude distillation unit is one of the processes most associated with sulphidation corrosion in petroleum refineries. However, the process hazard analysis of the crude unit did not consider the potential for sulphidation corrosion. The pipe in question was made of carbon steel which had a tendency to corrode from sulphidation faster than typical higher chromium-containing steels. In addition to that,  carbon steel also experiences significant variation in corrosion rates due to possible variances in silicon content, a component used in the steel manufacturing process. Carbon steel piping containing silicon content less than 0.10 weight percent can corrode at accelerated rates, up to 16 times faster than carbon steel piping containing higher percentages of silicon. This should be considered in the risk assessment

Source:IChemE

A LOOSE BEARING LOCKNUT CAUSES AN INCIDENT

On February 11, 2023, shortly before 1:00 p.m., a pump failure released hydrocarbons (primarily crude oil) and nitrogen oxide at a crude oil production facility in Texas. The crude oil released from the failed pump ignited, causing a fire that damaged nearby equipment and led to additional material releases The company estimated the property damage from the incident to be about $1.5 million.

The company's investigation found excessive wear and tear on the pump, which led to its failure. The company also found that the pump’s bearing lock nut, which holds the bearings in place, was loose. It concluded that this loose lock nut allowed the pump shaft to move and contact pump components, which caused pump damage that resulted in crude oil being released from the pump into the atmosphere. The company also concluded that heat from metal-to-metal contact in the pump seal area may have provided the ignition source.
During the incident, over 1,500 barrels of hydrocarbons (primarily crude oil) and over 1,200 pounds of nitrogen oxide were released.

Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the accidental crude oil release and fire was the failure of a crude oil pump. The released crude oil was likely ignited from heat from metal-to-metal contact in the worn pump.

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

"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/

 

 

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

SMALL THINGS MATTER IN ASSET INTEGRITY!

On January 21, 2023, at 4:30 p.m., 30 pounds of hydrogen gas were accidentally released from a shell-and-tube heat exchanger at a refineryin Louisiana. The released hydrogen caught fire, leading to an emergency shutdown, and caused over $1.5 million in property damage.
The hydrogen release originated from the flange between the heat exchanger channel and shell and occurred during unit startup. The heat exchanger was assembled in 2013 and had undergone 43 thermal cycles. During that time, the bolts had relaxed (a normal event) but had relaxed to the point that the flange could no longer contain the hydrogen within the heat exchanger. The company's investigation found that the bolt torque value used to assemble the heat exchanger in 2013 was too low and should have been much higher to prevent leakage.

CITGO found that the assembly instructions for both the incident heat exchanger and a nearby similar heat exchanger listed incorrect torque values that were too low, as the instructions listed the wrong bolt sizes. In addition, CITGO suspected that since it is common practice at the site to assemble similar flanges to similar torque values, the incorrect torque instructions from the nearby heat exchanger may have been applied to the incident heat exchanger. The company determined that the hydrogen may have ignited from contacting an adjacent hot heat exchanger, friction from the release, or a spark.
Probable Cause
Based on the company's investigation, the CSB determined that the probable cause of the incident was under-torqued bolts that had relaxed during 43 thermal cycles until the flange could not contain the hydrogen within the heat exchanger. Inaccurate assembly instructions and the likely application of incorrect assembly instructions for another heat exchanger contributed to the incident.

Source: CSB.gov

Introduction To Pipe Supports - GOOD VIDEO

Human factors during hydraulic torqueing of bolted joints

 SOURCE: https://www.stepchangeinsafety.net/alerts-moments/high-value-learning-hydraulic-over-torqueing-of-bolted-joint-equipment/

 Description of Incident

Two incidents have occurred during the hydraulic torqueing of bolted joints on assets operated by two different operators in the UKCS. In one instance, the event caused significant damage to the bolted joint; in the other event, the over torqueing value was identified before serious damage could occur.

In both instances the hydraulic torqueing equipment was wrongly set to a torque level higher than the bolted joint design value.

Common issues in both incidents include:

• The torqueing value was entered incorrectly (~1000psi higher than design)
• Both gauge faces involved contained both Bar and PSI scales
• Both torqueing sets were in a position where reading the gauge could be problematic due to the low angle
• No verification of equipment settings was carried out prior to torqueing equipment being operated

Good Practice Guidance

• Consider whether the gauge on the equipment you use is required to carry both Bar and PSI. Could it cause confusion?
• Consider whether your processes are sufficiently robust to prevent a similar incident occurring
• If you contract out this activity, consider how you assure yourself on the competence of the operators provided