By Chris Duncan, Business Manager, Emerson Automation Solutions
Detecting flammable gas that has the potential to threaten people and property in areas where gas clouds easily disperse is a problem in many applications. This recent case history is a classic example.
A UKCS (United Kingdom Continental Shelf) operator was issued an improvement notice from the Health and Safety Executive after a large volume gas leak went undetected on one of their North Sea platforms. The release had not been picked up by the platform’s existing flammable gas detection system because the gas had been dispersing as soon as it escaped.
The company contacted Emerson for help. The solution was to provide the Incus, an ultrasonic gas leak detector that, while working in conjunction with the existing gas detection system, added another line of defense and provided an early warning when gas releases occurred. Most importantly, it increased the safety of platform personnel.
Ultrasonic gas leak detection uses acoustic sensors to identify fluctuations in noise that are imperceptible to human hearing within a process environment. The sensor and electronics are able to detect these ultrasound frequencies (25 to 100KHz), while excluding audible frequencies (0 to 25KHz).
Unlike traditional gas detectors that measure the accumulated gas, ultrasonic gas detectors “hear” the leak, triggering an early warning system. The sensors respond to sound generated by escaping gas at ultrasonic frequencies. Leak rate is mainly dependent on the size of the leak and the gas pressure. In most facilities, the majority of process noise is in the audible range, while limited ultrasonic noise is generated in normal operation. Highly pressurized gas releases produce ultrasound (25-100 kHz) which the sensors are able to pick up despite the presence of audible noise. Ultrasonic (acoustic) gas leak detection technology has several advantages over conventional gas sensor technologies: it does not have to wait until a gas concentration has accumulated to potentially dangerous concentrations; it does not require a gas cloud to eventually make physical contact with a sensor; and the response is instantaneous for all gas types.
The Incus is ideally suited for monitoring outdoor applications such as on an oil platform. The Incus has been engineered to withstand even the most extreme conditions. Performance is not affected by inclement weather, wind direction, leak direction or any potential gas dilution, with an instantaneous response to all gas types. It is an excellent addition to many safety systems adding another layer of detection to existing technologies.
The Health and Safety Executive subsequently inspected the platform and approved the solution provided, resulting in a very happy customer!
Do you have an application that might require the addition of ultrasonic detection? It might be worth a discussion. Contact us HERE today.
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 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.
Infrared 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.
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:
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. http://www.hse.gov.uk/offshore/offshore-strategic-context.pdf
International Association of Oil and Gas Producers (OGP). 2006. Guideline for Managing Marine Risks Associated with FPSOs, Report No. 377. London, UK: OGP. http://www.ogp.org.uk/pubs/377.pdf
International Association of Oil and Gas Producers (OGP). 2010. Risk Assessment Data Directory, Report Vol 434-1. London, UK: OGP. http://www.ogp.org.uk/pubs/434-01.pdf
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. http://www.hse.gov.uk/research/otohtm/2001/oto01073.htm
By Edward Naranjo, Marketing Director, Emerson
Gas concentration is one of the most important determinants of a substance’s hazard potential. Flammability, toxicity, and oxygen deficiency are often determined by concentration. For combustible gas detectors, gas concentration is expressed as a volume fraction of combustible gas or vapor in air known as the lower explosive limit (LEL), while for toxic gas detectors, the signal output is read as a percent by volume (% vol.), parts per million by volume (ppm (vol.)), or mass per unit volume. Countries and jurisdictions use different units of measurement to define maximum permissible combustible and toxic gas concentrations in the workplace. The choice of the units to use depends on the chemical and its abundance under ambient conditions. As a result, it is necessary to become familiar with the units used and methods for converting between units of measurement.
Volume and Mole Fractions
Units of volume fraction and mole fractions are frequently used for gas concentration. The most common value fraction is ppm (vol.), defined as the ratio between the volume of a constituent Vi and the total volume Vtotal:
As an example, 10,000 ppm = 1% (v/v) or a volume fraction of 0.01. The volume fraction of a constituent φi is defined as the volume of constituent Vi divided by the volume of all constituents of the mixture Vtotal:
Similarly, the mole fraction of constituent Xi is the moles of a target substance n divided by the total number of moles in a mixture ntotal:
The values of volume fraction and mole fraction are identical under the ideal gas law:
The advantage of volume/volume or mol/mol units is that gas concentrations reported in these units do not change over temperature and pressure. By contrast, atmospheric concentrations like mass per unit volume (ex. mg/m3) decrease as gas is expanded since the component’s mass remains constant as the volume increases.
Mass Concentration Units
Concentration units based on mass include mass fraction (ex. mass chemical per total mass) and mass per unit volume. Like ppm (vol.), mass/mass concentrations are commonly expressed as parts per million, where mi is the mass of constituent i and mtotal is the total mass:
Note: Where a gas concentration is expressed simply as ppm, it is unclear whether a volume or mass basis is intended.
In the atmosphere, it is common to express concentrations of mass/volume air like milligrams per meter cubed (mg/m3). Thus, the United States’ National Institute for Occupational Safety and Health (NIOSH) Pocket Guide for Chemical Hazards reports worker exposure limits in ppm (vol.) and mg/m3. To convert from ppm (vol.) to mg/m3, it is assumed the ideal gas law applies under standard temperature and pressure where MW equals molecular weight:
Note that at standard conditions (p = 760 mmHg, T = 273°K), one mole of any pure gas occupies a volume of 22.4 L.
Another useful formula is one that converts from units of ppm (vol.) to ppm (m) at 760 mmHg and 25°C:
For convenience, NIOSH recommended exposure limits (REL’s) for several toxic gases are shown in Table 1 below.
Table 2 shows the LEL’s of several combustible gases in ppm (vol.), ppm(m), and volume fraction.
Last, conversion units for common industrial gases are illustrated in Table 3.
Situations Where Unit Conversions May Be Useful
It is tempting to think that converting units of measurement is hardly necessary. After all, in most countries, combustible gas concentrations are measured either in volume fractions or its derivatives, while toxic gas exposure limits are established in ppm (vol.) or mass volume units. Yet one cannot gauge a gas’ hazard potential without comparing attributes in a common plane. Consider that several toxic gases like ammonia and hydrogen sulfide are combustible. The graph in Figure 1 below showing gas concentration in ppm (vol.) gives a sense of toxic and combustible limits in relationship to one another.
Similarly, most hydrocarbons are harmful long before they are at combustible concentrations. As shown in Figure 2 below, the IDLH is often at approximately 10% LEL. Based on those results, an analysis of hydrocarbon toxicity recommended that alarm levels be set at 10% LEL to protect workers from hydrocarbon narcosis (Gardner 2012).
ISO 10156, Determination of Fire Potential and Oxidizing Ability for the Selection of Cylinder Valve Outlets. 2010. Geneva, Switzerland: ISO.
Gardner, R. 2012. Use of Reciprocal Calculation Procedures for Setting Workplace Emergency Action Levels for Hydrocarbon Mixtures and their Relationship to Lower Explosive Limits. Ann. Occup. Hyg. 56 (3): 326–339.
by Edward Naranjo, Marketing Director, Emerson Process Management, Rosemount Analytical
Gas detection systems are a common means of detecting and responding to the accidental release of hazardous materials. From their beginnings in the mining industry more than a century ago, gas detectors are now commonplace in the process sector and have become more effective as technologies have advanced and process safety standards become more widely accepted. Despite progress, instances exist where gas detection systems are not used appropriately. Alarm setting, in particular, is often done without considering if the release of concern can actually be detected at the alarm level or provides operators with enough time to respond to the hazard. As a result, some facilities are prone to experience inconsistent protection levels, high incidence of nuisance alarms, and in some instances, may be exposed to gas leaks that are detected at levels that exceed a safety basis [Center for Chemical Process Safety (CCPS) and American Industrial Hygiene Association (AIHA), 2009]. Poor alarm setting can increase the frequency of incidents if alarms’ limitations are not understood or warnings are ignored [Kletz, 2009].
To prevent these outcomes, operators must take a holistic approach to gas detection management. First, gas detection set points must be based on the hazard properties of the hazardous gas in question. For combustible gases, the low explosion limit (LEL) is the basis of alarm settings as established by a whole host of standards and federal, state, and local regulations [ANSI/ISA-TR12.13.03, 2009; HSE, 2004]. For toxics, alarm set points are based on worker exposure limits, usually the time-weighted average (TWA) threshold defined by local policies or legislation or immediately dangerous to life and health (IDLH) concentrations [Walsh et al., 2013]. ISA-92.00.02 (2013) advises one use:
“…the lowest level indicated in the current edition of OSHA (Occupational Safety and Health Administration) Title 29 Part 1910 Subpart Z, ACGIH (American Congress of Governmental Industrial Hygienists), and/or other local publications until determination of appropriate alarm levels can be made.”
Table 1 lists worker exposure limits for the United Kingdom’s Control of Substances Hazardous to Health (COSHH), OSHA, and IDLH values of several toxic industrial commodity chemicals.
It is not uncommon for operators to use two alarm levels, low and high, when monitoring for toxic substances. The low alarm provides an initial warning to assess the situation, while the higher alarm could prompt emergency procedures like evacuation and plant shutdown. Under ANSI/ISA-TR92.00.03 (2014), low level alarms should be activated when toxic gas concentrations reach the TWA level or lower; high level alarms should be set at or below the published STEL.
In the semiconductor industry, the maximum low level alarm is set at 20% LEL for combustible gases and half of the IDLH for toxics. In contrast, the maximum high level alarm is set at 40% LEL for combustibles and the IDLH for toxics.
Second, one must consider alarm set points are not static [CCPS and AIHA, 2009; Walsh et al., 2013]. While guided by industry practice and regulation, end users should aim at setting alarm set points as close to ambient conditions as possible without causing nuisance alarms. By doing so, they maximize the probability the gas is detected at a sufficiently early stage to allow for effective automated response.
For new types of detectors, operations, or process equipment, alarm set points should be established by first setting the alarm level at a regulated limit and retain it for at least 30 days. After reviewing trend data to identify peak and average gas concentrations, the operator should reduce the alarm set point until the minimum alarm level recommended by the manufacturer is reached or nuisance alarms are produced. To establish the optimum alarm set point, the operator can retain the high alarm at the last level that provided no nuisance alarms and then reset the low alarm to the next incremental setting.
While establishing alarm set points in gas detectors across a process unit or plant, it is important to note the alarm set points need not be the same. For instance, areas with high concentrations of target gas or cross sensitive gases require higher alarm set points to avoid nuisance alarms. Similarly, it is often necessary to set alarm set points of outdoor gas detectors at higher levels than indoor gas detectors, since those detectors outdoors are subject to wider changes in temperature, humidity, and solar radiation, which could result in nuisance alarms.
Some process units may experience short-term or periodic excursions of high gas concentrations. Rather than adjusting alarm set points upwards throughout the facility, operators may use two alarm set points to avoid nuisance alarms. One approach is to program the distributed control system (DCS) or control panel to annunciate at the high level and at the low level threshold if the duration of exposure lasts longer than expected excursions. Alternatively, one alarm could be annunciated if the alarm level is exceeded or if the gas concentration were to increase at a faster rate than expected by trend analysis.
Alarm setting is influenced by many factors. A first consideration is the type, number, and location of the detector(s). This is necessary to ensure adequate detection coverage and suitability for the intended task. For alarm setting, one should consider default levels set by the gas detector manufacturer, regulatory requirements like occupational exposure limits, or alarm set points specified by standards or guidance. After identifying these initial alarm levels, the next step is to lower set points balanced with minimizing spurious alarms. This requires trending analysis over a suitable period and experience with the monitored process and the instruments. Equally important, one must adjust alarm levels based on the environment (outdoors, indoors, confined spaces) to allow sufficiently early warning for emergency response.
ANSI/ISA-92.00.02. 2013. Installation, Operation, and Maintenance of Toxic Gas-Detection Instruments. Research Triangle Park, NC: ISA.
ANSI/ISA-TR12.13.03. 2009. Guide for Combustible Gas Detection as a Method of Protection. Research Triangle Park, NC: ISA.
ANSI/ISA-TR-92.00.03. 2014. Guide for Toxic Gas Detection as a Method of Personnel Protection. Research Triangle Park, NC: ISA.
CCPS and AIHA. Continuous Monitoring for Hazardous Material Releases. 2009. Hoboken, NJ: John Wiley & Sons.
HSE. 2004. The Selection and Use of Flammable Gas Detectors. Sudbury, UK: Health and Safety Executive. http://www.hse.gov.uk/pubns/gasdetector.pdf. Downloaded 20 July 2015.
Kletz, T. 2009. What Went Wrong? Case Histories of Process Plant Disasters and How They Could Have Been Avoided (fifth ed.). Amsterdam: Elsevier.
Walsh, P., Hemingway, M., and Rimmer, D. 2013. Review of Alarm Setting for Toxic Gas and Oxygen Detectors, Research Report RR973. Sudbury, UK: Health and Safety Executive. http://www.hse.gov.uk/research/rrpdf/rr973.pdf. Downloaded 20 July 2015.