1660339218637 Ian Verhappen

Intrinsic safety versus explosion proof

June 12, 2006
CONTROL contributing editor, Ian Verhappen, takes a look at why intrinsic safety is so popular in Europe and other areas outside the U.S., and why it has never really caught on yet here in North America.
By Ian Verhappen, Contributing Editor

THE PURPOSE of both Intrinsic Safety (IS) and Explosion Proof is to prevent a malfunction in a piece of electrical process equipment from initiating an explosion or fire through ignition of gases that may be present in the surrounding atmosphere. Both systems do this by keeping the potential energy level below that necessary to start the ignition process.

Intrinsic Safety manages the amount of energy available to a level below which ignition can occur. Explosion Proof on the other hand contains the energy of any possible explosion within the enclosure containing the possible ignition source. This containment is done through careful design of the enclosure so hat the resulting energy is not only contained; it is also dissipated through the large surface of the flanges or threads of the enclosure. Consequently, if the integrity of the enclosure is compromised, either because of a scratch across the flange face or threads or incomplete tightening of the cover, the result is a significant increase in the risk of an explosion. The net result is that Explosion Proof protection has a higher level of required maintenance than an Intrinsically Safe system. (See Figure 1 below).


Area Classification IIC IIB
Output Voltage (V DC) 30 42
Output Current (mA) 250 500
Output Power (W) 3.0 5.0
The approximate power limits for intrinsically safe apparatus in different area classifications.

Class 1, Division 1 (Zone 0) areas are defined as having combustible mixtures present routinely or all the time. The probability of a combustible mixture in Div. 1 is defined as 1 to 10-1. This type of probability is a very high risk if arcing devices are used, so Div. 1 electrical design is very conservative.  Div. 1 electrical designs allow for multiple simultaneous failures without the possibility of igniting a flammable mixture.

Generally arcing devices for Div 1 areas are sealed and contained in explosion proof containers. A practical alternate to this approach is to limit power delivery to the extent that it is impossible to generate a spark. This alternate is Intrinsic Safety.

Class 1, Div. 2 (Zone 2) areas are defined as areas where the likelihood of a flammable mixture is low, but it is significant enough that normal electrical activity should not present an ignition source. The probability of a flammable mixture in Div. 2 is defined as less than 10-5. Single failure tolerance with normal activities is much cheaper to design, construct, and maintain than the more redundant designs required for Div. 1. Div. 2 design is the most commonly found area classification in the USA. Unclassified areas have a negligible probability of hydrocarbons. This type of area classification might be found in an office building or control center.

Quick History Lesson
Chris Towle, Secretary to several IEC standards committees and a long time practitioner in the field of electrical safety provides the following bit of background. “Intrinsic safety took off in Europe when transistorized equipment became available,” Towle says, “and computer control became the norm. Possibly the principal factor for the different approach was the area classification. The existence of Zone O, where the flameproof technique was not acceptable, required that intrinsic safety had to be used for some sensors, and since it had to be used for this purpose it became a recognized practice. There was no corresponding requirement imposed by Divisional classification. In 1960 to 1980 most of the investment in Europe was in petrochemicals and pharmaceuticals. This was predominantly done by companies with their own engineering capabilities who were not involved in petroleum refining.”

EPA Says "No!"
In the not too distant past, process leaks were very common. Leaking pump seals were a major culprit and were often tolerated as long as the leaks were small. Consequently, areas around pumps were generally treated as hydrocarbon sources with a moderate likelihood of some hydrocarbon present. If these pumps were in an open area with free air flow and maintenance was not too lax, the envelope around the pump would be classified as Div. 2. If the pump was in an enclosed area, the same envelope would be classified as Div. 1.

Because of these continuous leaks, the EPA made these pump leaks illegal. We now have double sealed or canned pumps, with monitoring programs to make sure ppm leaks are detected, corrected, and reported - far below the threshold of flammability. Average pump seal life has gone from a few months to 7 years and as a result the likelihood of a flammable mixture has dropped a few orders of magnitude over the last 30 years, and for the reasons just described, Div. 1 areas are illegal (by EPA standards) in the USA.

About the time that IS designs were made more widely known in North America, the US started cleaning up leaks and the need for IS went away. IS designs never caught on. Because of environmental changes, Div. 2 designs appear quite robust, and Div. 1 designs appear to not be required in most market installations.

Joe Kaulfersch, market analyst for Pepperl+Fuchs Americas says, “Most users believe the cost is higher and it is more complicated to have intrinsic safe circuitry.  However, the cost of ownership is much lower considering customers want to have higher system availability and be able to produce product without shutting down in addition to running the process safely. With Explosion Proof equipment the electronics must be locked out and turned off.” Unfortunately, with fieldbus systems this is not possible as they must be worked on live and connected to the network.

In part to help dispel these misunderstandings, MTL Instruments have prepared a publication “Cost comparison of methods of explosion protection” TP1110-3 that is accessible from their web site. Based on their analysis, the installed cost of an IS analog loop is 16% less than Explosion Proof while for a discrete signal this is 17% less expensive.

Despite claims that Intrinsic Safe installations allow Live Maintenance, in practice they, like Explosion Proof require the use of hot work permits because many of the maintenance tools used are not IS and the work itself has the potential of creating a spark of sufficient energy to initiate a conflagration. The MTL report investigated the potential impact of maintenance on ownership over a 10 year period by taking into account the effort required in permitting associated with maintenance, finding that for a discrete signal (38% cheaper for I.S.) and analog signal (34% lower for I.S) the savings continue.
Where are we today?

Herman Storey from a major oil and gas company states “We use neither explosion proof nor IS. Our plants are classified as Division 2 and neither EX or IS classification is required. I think plants in Europe will move to Zone 2 as well because of ATEX and the impossibility of complying with Zone 1 for mechanical equipment.”

Storey continues, “The reason we use Non-Incendive rather than IS is that IS simply doesn’t make any logical sense if you follow it through. You get into arbitrary safety factors that are compounded many times, and it gets expensive. Non-Incendive was designed with Zone 2 in mind and it makes good risk management sense.”

United Kingdom-based Chris Towle, states, “The only reason for sticking to explosion proof for instrumentation is inertia.” He then goes on to say “I believe the major change in the use of IS will come with the acceptance of the “ic” concept in Zone2/ Division 2 to replace the “non-incendive/ energy limited” concept. This should clarify the requirements for instrumentation in Zone 2 and lead to uniform practice applicable to all Zones.”

Dermot Coady, group business manager at MTL Instruments says, “One of the perceived limitations of IS is the unreliability of low powered solenoid valves. This was true in the early days of IS installations however the design and reliability of these devices have significantly improved to such an extent that's no longer considered an issue.”

When asked why IS is not being used in the US, Joe Kaulfersch replied, “In  North America most hazardous locations are considered Class I, Div. 2  which  very closely resembles the Zone 2 specification of Europe. The fact is many of the European factories are located very close to large populations. Even though Zone 2 classifications are relatively safe, there has never been an accident on record with an intrinsically safe installation. Insurance companies like to eliminate risks rather than mitigate risks. North American engineers are reluctant to use ‘new’ technology even though it is 47 years old.”

Storey summarizes the current state of affairs best. “I don’t think the USA will ever move toward IS,” he says;“It could go the other way if anyone ever tried to make sense of the problem.”

  About the Author
Ian Verhappenis an ISA Fellow, Certified Automation Professional, Adjunct Professor at Tri-State University and Director ofICE-Pros Inc.an independent Instrumentation and Systems Engineering firm focused on Fieldbus technology, process analyzer systems and oil sands technology. He can be reached at [email protected]or via the web atwww.ICE-Pros.com.

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