Do We Need IS?
Dicaire of Emerson says one reason for the low demand for IS in North America is because plants are being built safer these days to meet regulatory targets. “Improved valve packing and seals on field equipment have minimized fugitive emissions, allowing companies to significantly reduce or even eliminate the areas needing Zone 1 classification,” he explains. “So even in new installations where IS can be introduced, the percentage of I/O signals that require it is small.”
At least two observers have questioned the need for intrinsic safety, including our own columnist, John Rezabek, and Mike O’Neill, director at MooreHawke.
Rezabek says in his March 2008 column "Instrinsic Safety Obsolete Yet?," “Why do we install an intrinsically safe instrument system? One reason is the ability to do live work, such as connecting and disconnecting an instrument for calibration or troubleshooting. The other reason is the significant likelihood that the area where an instrument is located routinely has a flammable or explosive mixture of fuel and air present. We’re at a point today where, in many cases, both of these needs are going to or have gone away already.”
O’Neill says, “IS systems were great for analog electronic modules that needed frequent access in the field and for the adjustment of limit switches on valves. Fieldbus devices have no physical adjustments accessible in the field or otherwise, and all changes are made through the segment communications, so putting yourself through the pain of IS fieldbus—and it can be very painful indeed—is not necessary at all! However, company specifications don’t always follow technology very fast.”
Even if it’s true that modern instrumentation and plant design have virtually eliminated problems in hazardous areas, the rules-makers haven’t gotten the message—and it’s the brave corporation that’s willing to eliminate safety systems where they have always been installed. Whether you choose explosion-proof or IS, a legion of local, state, national and international standards organizations, your own company policies and the requirements of your insurance carrier will determine what safety systems you will use.
Rich Merritt is a Control contributing editor.
Playing by the Rules
One problem with both systems is the bewildering array of rules and regulations regarding hazardous areas and classifications. The “zones,” “divisions” and other categories that vary from sytem to system and standard to standard make it hard to tell the players without a detailed scorecard.
Gus Elias, standards specialist at Moore Industries, explains the differences between the European ATEX rules and the U.S. and Canadian National Electrical Codes (NEC/CEC): “In the U.S., the classification of hazardous locations is based on the NEC, while in Canada the CEC applies. In Europe, Asia and Australia, the tendency is to follow the recommendations of the International Electrotechnical Commission.”
While similar, their definitions of hazardous areas differ:
“It’s important to note that Zone 2 (IEC/Europe) and Division 2 (North America) are similar to a great extent, but are not identical, while Division 1 includes the corresponding Zones 0 and 1,” notes Elias. ( For a quick rundown on the differences see Dan Hebert’s Dec. ’08 Technically Speaking column "Sorting Out ATEX.")
Elias says these seemingly minor details have tripped up a number of major control system vendors, who found that their intrinsically safe I/O systems, which met NEC/CEC requirements, did not meet ATEX requirements, and they lost a number of large jobs in Europe as a result.
Things may be changing. “U.S. plant installations were historically based on NEC500 [divisions], but in the future, new plants may be designed to NEC505, which encompasses zones and follows IEC standards,” says Elias. “This will allow the worldwide use of similar apparatus and wiring methods, including an increase in the use of intrinsic safety.”