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Good morning fellow engineers, technicians and technologist.
Today on the menu is Zone Classification.

I do hope you savour the dish served and it helps you in learning a thing or two weekly.

As you enjoy the meal served here today remember, Safety is everyone's responsibility and you are as safe as your neighbour safety habits....so watch out for an unsafe job, colleague or contractor today.




MAIN COURSE
Usually classification according to zones are done in the oil and gas industry to assist, workers as well as contractors know the hazard such areas exposes them to.
For the process engineer, the Operation spervisor it tells much more than this as it offers then process equipment safety design guide. It also is used in ESD philosophy. ESD meaning Emergency ShutDown system.
The Fire and Gas-F&G system requirement is also based on the zone Classification.

So an bad zone classification design might result in process safety design flaws as this will inturn lead to serious incidents or accidents.

Also, since the field of engineering, is the only one in contious tense, emerging data might mean and earlier known classification can be declassified as new data comes in.

The types of zone classification are Zone 0, Zone 1 and Zone 2
Zone 0-----Non availability of HC hazards

Zone 1------Presence of HC in a controlled environment, examples include HC (Hydro carbon) in a pipe or vessel.


Zone 2-----Presence of HC in a likely difficult to control environment like Gas Compressors sides, where a seal failure will always means Gas are vented to the environment.


Some places the zones are classified from 3 to 1, or 2 to zero, however which ever way it is classified it is best you are armed with a fore knowledge.




DESERT:
Over the past several decades, a leading overseas HPI corporation experienced a disturbing number of explosions in its belowground hydrocarbon sump pits.
Over the past several decades, a leading overseas hydrocarbon processing industry (HPI) corporation experienced a disturbing number of explosions in its belowground hydrocarbon sump pits.
Gravity-fed oily water “slop” and spillage from surrounding process facilities feed into these concrete pits; they typically range from 15 ft to 35 ft in depth. An unpredictable product slate causes the sumps to be exposed to two highly undesirable conditions: a volatile hydrocarbon mixed with air, and an enclosed space.
It can take only a temperature excursion to spark a blaze. Equally unpredictable and random, this high temperature can be caused by a spark or through rubbing contact of metals, with resulting temperatures above 600°F.
At the overseas corporation’s facilities, the recorded ignition events had their origins in external triggers—lightning, nearby welding, etc. Also, at other times, internal causes were responsible. Both small and large components were known to occasionally fail in American Petroleum Institue-compliant vertical sump pumps of various designs and types.
Relevant input from a senior corporate reliability engineer at that corporation is hereby gratefully acknowledged. The engineer asked for comment on similar occurrences at other facilities and an outline for the steps needed to address this important safety concern. In the past six years, the staff at his corporate offices had examined and researched several risk-abatement solutions. Management then agreed to proactively pursue a set of mandatory facility improvements that called for or included :
1. Maximized use of aboveground, self-priming, motor-driven centrifugal pumps on new and existing installations as a mandatory design requirement. Such pumps must be approved by the manufacturer for hydrocarbon liquid operation and include liquid-filled mechanical seals, full stainless steel construction and temperature sensors.
2. Utilization of carefully designed vertical centrifugal pumps for pits where greater depth makes aboveground horizontal pumps impractical.
3. Consideration of submersible electric-powered pumps as unacceptable due to the possibility of electrical ignition from damaged cables or dry running. However, ATEX-certified hydraulic-powered submersible sump pumps with an external drive source for smaller pits are considered acceptable.
4. Installation of redundant radar-type liquid level gauges on all sump pits. (These gauges have the highest proven reliability in sump service.)
5. Reduction of the possibility of hydrocarbon entry into oily-water sumps (“slop pits”).
6. Requiring pressure switches or flowmeters with time delay on the sump pump discharge piping, which will shut down equipment in the case of no-flow events.
The corporate reliability engineer mentioned that, notwithstanding point No. 5, the refinery process units would most likely continue to route every conceivable type of runoff to the sump pits. He considered it virtually impossible to fully control such drainage. Accordingly, he suggested that the importance of the issue be highlighted to HPI plant safety worldwide.
He has been uncomfortable with belowground pits in hydrocarbon processing plants. Early in his 30-year career, he realized that applicable loss-prevention standards disallow below-level installations, although sump pits with hydrocarbons abounded both then and now. He reaffirmed that potential pump-related ignition sources included defective pumps, dry running pumps and faulty cables on submersible pumps.