By Jim Cahill, Emerson

This post was originally published on Emerson Exchange 365 and we wanted to share it with our readers as well.

At the Emerson Exchange conference in Austin, Emerson’s Sean McLeskey presented Fixed Gas and Flame Detection Best Practices. His abstract:

Many industrial processes involve dangerous gases and vapors: flammable, toxic, or both. With the different sensing technologies available, and the wide range of industrial applications that exist, selecting the best sensor and locating them properly for the job at hand can be a challenge. This workshop will help you get a better understanding of application challenges, learn basic installation best practices, and understand the benefits of using flame and gas detection solutions.

sean-mcleskey-emrexSean opened with a safety case study at a refinery where personnel heard a “pop” and saw what appeared to be steam. It was a gas release that led to people being injured and the refinery being shut down for 3 months with losses in the tens of millions.

Fixed flame and gas systems are for detecting releases of process hazards and provide time to alert personnel and put the process into a safe state. These systems protect people, property, provide regulatory compliance and maintain good relations in the surrounding community.

Ultrasonic gas leak detection listens for the ultrasonic sound caused by escaping gas. It is not impacted by wind direction that some other detector technology relies upon. It provides first detection but does not provide composition of the gas detected.

Another technology is point gas detection which requires the gas to pass by to be detected by the sensors. This technology is typically applied near leak sources where the escape points, such as gaskets are known. One example technology is catalytic bead combustible gas detection. This technology is used to monitor several targeted gasses across applications including hydrogen.

fixed-flame-gas-detection-1Infrared sensors are another type of point gas detectors. Their strengths compliment catalytic bead. It is unaffected by high concentrations of hydrocarbon and works in the absence of oxygen, unlike the catalytic bead technology.

Multi-spectrum infrared flame detectors are the highest performing detectors and have excellent immunity to false alarms.

After performing a risk assessment, installation considerations include pressure of gas source—is it high enough for ultrasonic listening. For the point gas family of technologies gas must be able to reach the sensor. Considerations include the properties of the gas, ambient conditions and obstructions between the gas source and detector, open path technology to cross beam path. Depending on the area where the detectors are located, beams, point gas and ultrasonic listening have advantages and disadvantages.

For flame detectors, the optical sensor is like an eye. Considerations include the size of the area to be monitored, detection technology, obstructions, nature of flame source, and potential blind spots.

No one detector is a silver bullet for use in all applications. Each has their advantages and disadvantages and you will need to consider your application. You can connect and interact with other gas and flame detector experts in the Analytical group in the Emerson Exchange 365 community.

By Edward Naranjo, Emerson Process Management, Rosemount

Over the last 30 years, the use of FPSOs (Floating, Production, Storage, and Offloading) and other Floating Storage Units (FSUs) has emerged as a key technology to produce oil and natural gas from subsea fields. These vessels can be deployed quickly, and advances in FPSO technology have allowed them to operate in increasingly severe environments and deeper water, and to handle higher pressure and more wells. Not surprisingly, the share of offshore production installations comprised by ships is growing, accounting for 30 percent of the UK Continental Shelf production, in one instance [UK Health and Safety Executive (HSE), 2014].

Despite the increasing number of floating production installations, controlling hydrocarbon releases and reducing the risk of fires and explosions remain key concerns for FPSOs. As higher temperature, higher pressure reserves are harnessed, exploration and production equipment is subjected to greater stress. According to the UK Health and Safety Executive, FPSOs and FSUs have a higher rate of hydrocarbon releases than fixed installations [HSE, 2014].

Most FPSO risk assessments identify the turret system as one area of potentially highest risk [International Association of Oil and Gas Producers (OGP), 2006; HSE, 2014]. Turret systems are the structure from which production fluids from the flexible risers are transferred to the process plant on the vessel by a swivel or other fluid transfer system. Turrets maintain the vessel on station through single point mooring and allow rotation of the vessel to adopt the optimum orientation in response to weather and current conditions. In most cases the vessel can freely rotate through 360o. An FPSO turret system comprises three main systems: the turret; a fluid transfer system (FTS), a multi-path swivel to transfer the production fluids to the process plant on the vessel; and an intermediate manifold known as the turret transfer system (TTS) that links the turret and the fluid transfer system. All parts of a turret system are shown in Figure 1 below.

Figure 1. FPSO Diagram Showing Cross Section Through an Internal Turret
Figure 1. FPSO Diagram Showing Cross Section Through an Internal Turret

As with other offshore systems, FPSO turret systems can be subject to degradation in service. Corrosion, abrasion or fracture, and changes in material properties can lead to loss of containment of hydrocarbons. Likewise, hydrocarbon releases can also result from poor maintenance practices, insufficient operational controls, or damage from dropped objects. Regardless of failure mode, ignition of released hydrocarbon can cause or contribute substantially to a major accident.

According to a report commissioned by HSE [Wall et al., 2002], the consequences of a turret explosion could be the following:

  • Structural damage or plastic deformation of the turret
  • Fatality to all individuals involved in the initial blast
  • Serious injury confined to turret and immediate surrounding areas
  • Local escape and evacuation routes potentially destroyed or damaged
  • Process area inventories potentially vulnerable to exposure to fire, which with escalation could lead to explosion

According to the same report, the frequency of hydrocarbon gas releases within the turret system is approximately 2 x 10-2 per year and that of turret explosion is 2 x 10-4 per year. The gas release frequency is similar to that of reciprocating compressors (7.1 x 10-2 per year) and centrifugal compressors (1.1 x 10-2 per year) used in offshore and onshore installations [OGP, 2010], and other process equipment used for the handling of fluid.

Because control measures may fail, it is essential for turret systems to have such measures in place as flame and gas detection and fire deluge arrangements. Ultrasonic gas leak and point combustible gas detectors can be installed to monitor the turntable manifold and the fluid transfer system, which has high pressure dynamic seals. In offshore production in the UK, many of the reported incidents between 1995 and 2000 have been associated with the turret transfer system in internal turret designs. The combination of ultrasonic gas leak detection with point gas detectors is particularly effective, since leak detectors respond to the source of the release, while gas detectors help assess hazard severity. Other areas to monitor are the swivel access structure and the gas export swivel.

In some instances, it might be necessary to monitor path of travel to protect worker accommodations, many of which are close to the turret system in internal turret designs, as well as the process plant. In such cases open path detectors could be beneficial. Similarly, flame detectors are required to monitor the main turret, the multi-path swivel stack of the fluid transfer system, and the turntable manifold of the turret transfer system. In the fluid transfer system, it is not uncommon to site one or more flame detectors on each story of the swivel access structure.

Floating structures for production, storage, and offloading have been used safely and reliably over many years. Turret technology has played a key role in mining fields, as turrets have become larger and more complex to handle increasing levels of production and the particular process conditions of individual wells. Nonetheless, with higher throughput and operation in increasingly severe environments, addressing the potential of hydrocarbon gas releases becomes an important element in accident mitigation.

One tool to reduce the risks of escaping gas or process fluids is flame and combustible gas detection. Ultrasonic and combustible gas detectors may arrest the escalation of an incident, while flame detectors can offer early warning of jet fires. Since no one detection technology is 100% effective, the use of a combination of ultrasonic gas leak detection, gas detection, and flame detection increases detection efficiency and offers the most effective means to reduce the consequences of hydrocarbon releases. More information on gas and flame detection solutions can be found here.

How have you set up your gas and flame detection systems to help ensure the best possible safety coverage for your application?



HSE. 2014. Offshore Oil & Gas Sector Strategy 2014 to 2017. London, UK: HSE Books.

International Association of Oil and Gas Producers (OGP). 2006. Guideline for Managing Marine Risks Associated with FPSOs, Report No. 377. London, UK: OGP.

International Association of Oil and Gas Producers (OGP). 2010. Risk Assessment Data Directory, Report Vol 434-1. London, UK: OGP.

Wall, M., Pugh, H.R., Reay, A., and Krol, J. 2002. Failure Modes, Reliability and Integrity of Floating Storage Unit (FPSO, FSU) Turret and Swivel Systems, Offshore Technology Report 2001/073. Abingdon, UK: HSE Books.

23 Mar, 2015  |  Written by  |  under Flame Detection

by Srikanth Vengasandra, Ph.D., Product Manager, Flame & Gas Detection Group, Rosemount Analytical

On January 1, 2015, eight tanks at a truck unloading station in Alexander, North Dakota, caught on fire, setting ablaze approximately 1,600 barrels of crude oil1, 2. Although the cause of the fire remains under investigation, the incident underscores the need for preventive and alternative methods to protect against the risks of tank fires and explosions3.

Often the most common type of fire in floating roof tanks is the rim-seal fire. Rim-seal fires occur whenever crude oil vapors escape through worn seals, accumulating on tank skirts. These leaked vapors can be ignited, often by lightning, resulting in a fire around the tank perimeter. According to data obtained from the Large Atmospheric Storage Tank Fire (LASTFIRE) project, rim-seal fires occur at a rate of 0.3 to 21 x 10-3 incidents per tank year, with Nigeria, Thailand, and Venezuela reporting the highest frequencies3.

Suitable design, construction, maintenance of storage systems, and overfill and leak protection take precedence over any protective scheme, since they are preventive layers. They help prevent crude oil inventories from escaping in the first place. A host of mechanical integrity management standards address the provision for inherently safe design4.

Fig. 1: Detection Coverage of Floating Rooftop Using UV/IRS Flame Detectors.

Fig. 1: Detection Coverage of Floating Rooftop Using UV/IRS Flame Detectors.

A second priority is the establishment of leakage, overflow, and flame detection. These measures help to reduce the consequence of a material release after loss of containment has taken place. In particular, flame detectors should be used for monitoring bunded fuel tank areas and rooftops. Figure 1 illustrates a typical arrangement for protecting the latter. The CAD drawing shows the top view of a crude oil tank 77 meters in diameter and 16 meters tall with the overlapping coverage from six UV/IRS flame detectors, FD#1, FD#2, FD#3, FD#4, FD#5, and FD#6. The number of flame detectors is determined from the fuel source and the associated flame detector coverage angle of 120° in the horizontal plane at a distance of approximately 43 meters from the fuel source.

In addition to protecting rooftops, flame detectors are also used to mitigate the risk of fires produced from bottom leakage. These fires are common to fixed, floating room, and domed roof tanks and are treated like large pool fires. Rarer than rim fires, small and large bund fires occur at a rate of 9 x 10-5 and 6 x 10-5 incidents per tank year. Because dikes prevent the spread of tank contents, it is usual to install flame detectors in the dike perimeter, typically in corners and trained toward the base of the tanks5.

The main hazards associated with the storage and handling of combustible liquids are fire and explosion.  As the size of tanks and inventories in terminals increase, so too has hazard severity. For floating roof tanks, rim-seals should be constantly monitored by the use of flame detectors, and similarly, flame detectors should provide a large zone of detection for bunded areas. Together with combustible gas detection, they offer an effective means to cope with fire hazards.


1 Eckroth, L. 2015. Oil Storage Tank Fires Extinguished. Bismarck Tribute,

2 Scheyder, E. 2015. Oil Storage Tanks in North Dakota Catch Fire; No Injuries. Reuters,

3 Marsh. 2011. Atmospheric Storage Tanks. Marsh,

4 Holmes, A. 2009. Mechanical Integrity Management of Bulk Storage: Review of Standards, RR760, Health and Safety Executive,

5OGP Risk Assessment Data Directory, Report No. 434-3, March 2010. Storage Incident Frequencies, International Association of Oil & Gas Producers.

by Edward M. Marszal, PE, ISA84 Expert

Gas detection is ubiquitous in a wide range of process industry applications where leaks of process equipment can result in either toxic or flammable gas clouds that can hurt people or property. Even though the detectors are ubiquitous now, their application is relatively new. In fact, only a few dozen years ago in the offshore oil and gas industry, the state-of-the-art gas leak detection was to measure the pressure in vessels in piping. If it was found to be below the trip point, then there had to be a leak somewhere.  You would probably be shocked to know how many existing platforms in the Gulf of Mexico are still operating under this philosophy. As a result of the relative novelty of gas leak detection systems, the methods utilized to determine how many detectors are required and where they should be installed are also still in their infancy. But with the help of organizations like ISA, companies are starting to get more technically rigorous in gas leak detection and adoption is growing. In this blog series, I’d like to present a brief history of how detectors were placed in the past, discuss gas detection best practices, and then talk about where the industry is headed.

When gas detection instruments such as catalytic bead systems, point IR detectors, and electrochemical cells were first put into use in process industries, their placement was much more of an art than science.  Industry employed veteran instrumentation and control engineers and safety engineers to use their “experience” to place detectors. These experts considered rules such as finding points where gases would accumulate, points where gases would be released, and measured the density of the released gas versus air to determine where detectors would be required. Unfortunately, these rules were often inconsistent among different experts, and led to widely different designs for similar facilities. Furthermore, studies, including ones performed by the UK Health and Safety Executive (HSE) found that the placement of fixed gas detection systems only identified less than 70% of the “major” gas releases that occurred in the process industries. This type of performance was deemed to be not acceptable, especially after a number of process industry accidents where detection systems failed to identify problems.

The poor performance of the “expert judgment” or heuristic placement techniques resulted in the first-wave application of more quantitative scientific analysis of detector placement. The next generation of detector placement is what we refer to as “the grid.” Loss prevention engineers, with a great deal of help from the UK HSE, made the decision that a good philosophy for the placement of gas detection equipment would be that if a gas cloud exists in a facility that is large enough to cause damage, it should be detectable by the gas detection array. HSE then undertook a program of study that determined that this objective could be achieved if gas cloud diameters could be limited less than 7 meters.  If limited to this size, then the distance that a flame could travel through a gas cloud would be less than 7 meters which has been experimentally determined to not result in a vapor cloud explosion in most typical release scenarios.

Once the distance across the cloud was determined, the objective was to make sure that a cloud of that critical size could not hide in-between detectors without being identified.

The Dirty Bubble
Some of us practitioners affectionately call this cloud of critical size, “The Dirty Bubble” – a reference to a super-villain in the SpongeBob Square Pants cartoon that most of our children watch (and usually, us with them…). In order to ensure that the dirty bubble would always be identified by at least one detector, HSE determined that detectors placed on a five-meter grid would be required.  Subsequently, a lot of designs – at least for offshore oil and gas production – were based on a five-meter grid.

A couple of problems were identified in the five-meter grid process. First off, the five-meter grid only worked for point detectors, and a lot of operating companies were starting to use open-path detectors.  Second, the five-meter grid process did not differentiate areas of plants where leak sources did not exist, and thus leak detection would seem inappropriate. The grid system also was only applicable to combustible gases, and application of this approach to toxic gases was not effective, as there is no “safe” toxic gas cloud size. And finally, even if the hazard of concern was combustible gas, the efficacy five-meter grid is dependent on a number of specific parameters, such as the reactivity of the hydrocarbon gas and the amount of confinement of the gas cloud. For highly reactive hydrocarbons – such as ethylene oxide – five meters allows too big of a cloud, whereas methane in an open area would require a cloud much larger than five meters to be dangerous. The five-meter grid was a great starting point, but the limitations quickly became obvious, and solutions to the limitations were rapidly developed.

Gas Detection Coverage Map – Geographic Coverage – Kenexis Effigy™

Gas Detection Coverage Map – Geographic Coverage – Kenexis Effigy™

The next evolution of methodology for gas detector placement was the advent of what is now referred to as fire and gas mapping. This evolution focused on considering what fraction of an area is “covered” by a gas detector array. For gas detectors, this is essentially a function of the size of the “dirty bubble.”  If the critical gas cloud size is five meters, then if a detector is within five meters of the center point of the cloud, it is “detectable.” Based on this theory, one could then plot the areas surrounding a detector that could be covered. The most primitive forms of this type of coverage analysis simply drew circles around point detectors on a plot plan drawing. As the technique developed, computer software was developed that would draw the coverage areas and calculate the fraction of covered area, along with distinguishing areas that were covered by a single detector from areas that were covered by two or more detectors. The advantages of this approach over simple grid placement were quickly apparent and quickly and widely adopted. The advantage of the coverage approach was that different critical cloud sizes could be defined for different hazard scenarios, and the total area that is desired to be covered could be limited to “graded areas” where hazards are known to exist – allowing non-hazardous areas to be ignored in the analysis. An example of a geographic coverage map created in the Kenexis Effigy™ FGS mapping software is shown in the figure above.

Gas Detection Coverage Map – Geographic Coverage – Kenexis Effigy™
At present, geographic coverage mapping for gas detector placement is the most commonly deployed sophisticated methodology for gas detector placement. But, other methodologies that are technically more robust are in rapid development and deployment. Our next blog post will address these new next-generation technologies.

20 Nov, 2013  |  Written by  |  under Flame Detection

FGD_PUB_201211_Petroleum_Review_Minimising_False_AlarmsHi everyone. I’m Jonathan Saint with Net Safety and I want to talk about ways to prevent false alarms with flame detectors. I wrote on this topic in a recent edition of Petroleum Review. If you’d like to see the whole article, click HERE.

Most flame detectors function using optical systems like ultraviolet (UV) and infrared (IR) spectroscopy. Almost all flames produce heat, carbon dioxide, carbon monoxide, water, carbon and other products of combustion, which emit visible and measureable UV and IR radiation. These spectral emission “by-products” are what flame detectors sense to quickly and accurately determine the presence of a fire. These same emissions from non-flame sources cause nuisance false alarms and plant shutdowns.

Today’s optical flame detector options include single wavelengths of UV and IR, integrated UV/IR sensors, and more advanced units that offer triple wavelength IR sensors. The performance and advantages of each of these systems vary a lot.

A huge consideration in the selection of a flame detector is the potential for false alarms. False alarms are generally not the result of an issue with an instrument but rather its response to non-flame radiation sources that fall within their field of view. There are two basic types – natural and man-made. Natural sources include rain, lightning and sunlight while man-made source examples are artificial light sources, welding, and radiation from heaters and machinery. And falling into these two primary sources are four primary types: solar-blind UV; window contaminates; non-modulated IR; and modulated IR sources.

With non-modulated sources of radiation, the energy is constant over time or varies at an extremely slow rate. Examples of these are IR energy emitted from heaters, lamps and heat from the sun. Additionally, there’s a small amount of IR radiation emitted from all objects which is constantly present in any detector’s field of view. To overcome this, the majority of flame detectors available on the market today are designed to only detect modulated IR radiation sources – a key characteristic of flames. With modulated sources, characterized by varied and sporadic energy or as a combination of non-modulated sources, identification can be very challenging. Examples of these false sources are heated emissions, moving lights, signals or combinations of non-modulating sources being altered by objects moving back and forth in front of them in between the source and the sensor (vehicles, personnel, or fan blades for example). This is overcome by the use of multi-bands which can distinguish on the IR spectrum between flames and other sources of radiation.

While UV detectors work well in sunlight, other factors in outdoor applications may negatively affect them. UV sensors are designed to monitor solar-blind UV, the band of UV energy that is blocked by the ozone layer in the upper atmosphere. Powerful sources of this energy wavelength are commonly produced in industrial settings by halogen lamps, arc welding and even lightning. Additional bands can be employed, or combined UV/IR detectors will overcome almost all of these sources of inference.

Finally, window contamination will negatively affect the detector’s performance and can cause the instrument to go into fault mode. Attenuating energy sources will hit or deposit on the window face of the detector as well as accumulate on external reflectors used for automated visual integrity testing. Water droplets, condensation, snow and ice are powerful absorbers of IR energy that can be delivered in random scales and intensity and are a well-known source to trigger false alarms or faults when combined with modulated energy sources like direct sunlight. UV radiation is also easily absorbed by a range of oils, smoke, carbon and specific gases. Engineers need to be aware of the presence of vapors such as hydrogen sulphide, benzene, ammonia, ethanol, acetone and others when selecting a flame detector for their application.

There’s no perfect flame detection system for every application – all have challenges. But understanding the type of fire to be detected, the environmental conditions surrounding the installation, and the required performance makes the choice of flame detection technology a much more manageable decision. A detection solution that allows for field sensitivity and time delay settings will help mitigate the more challenging false alarm sources by allowing users to fine-tune their instruments in situ for optimal performance.

What type of flame detection system do you use? Do you experience any problems with false alarms?