Environmental Monitoring Equipment & Supplies • Sales, Rental & Service by Enviro-Equipment — Charlotte, North Carolina USA

NEC

Selling remediation equipment is not like selling donuts, but both can give you a stomach ache at times. On occasion we receive really good bid documents and drawings, other times it might be a phone call and a sketch. In either case, we can’t just take the bid request at face value and give them what they ask for when we often find critical mistakes in their design.

In the past two decades a lot of the remediation projects out for bid were being funded by STATE UST trust funds with getting things done “for cheap” being the main focus. In addition, it appears that consulting companies are spending a lot less time and money training young engineers and scientists on how to properly design a remediation system from pilot test results (if one is performed). The States have created reasonable rate documents that dictate how much they will pay for certain tasks no matter what it costs to do it correctly. Unfortunately, this leads to a lot of cut and paste designs to keep costs down, creating a lot of critical mistakes. It is not unusual for us to see equipment or controls listed in the bid document that have been discontinued for 5 to 10 years. We also see incorrectly sized blowers or compressors and motors specified that will not operate on the power available at the project site.

Recently, we had a quote request for a soil vapor extraction and air sparging system. The customer mentioned that it was a UST site, and that gasoline vapors should not be present in the vented container, just in the vapor conveyance piping and liquid separation tank. They did not believe it was necessary to include an explosion proof (XP) design (Class 1 Division 2 Group D) in their specifications. The system was designed to be in a single room trailer with all the components and wire non-XP.

A portion of the email from our Division manager to the engineer explaining exactly why his design should be revised is presented below. Information pertaining directly to this situation has been made bold:

I have to respectfully disagree. We’ve built countless SVE systems such as this and even have them inspected by a third party laboratory for NEC/UL/NFPA codes and this system absolutely would be a Class 1 Div 2 Group D location.

Just because the vapors SHOULD be contained in the piping, doesn’t mean if a leak occurs they will stay there. In normal conditions they won’t be present. In abnormal conditions, there’s a possibility they will be. Therefore it’s a Class 1, Div 2, Group D location.

Source: https://www.osha.gov/doc/outreachtraining/htmlfiles/hazloc.html

Hazardous Location Conditions

In addition to the types of hazardous locations, the National Electrical Code also concerns itself with the kinds of conditions under which these hazards are present. The Code specifies that hazardous material may exist in several different kinds of conditions which, for simplicity, can be described as, first, normal conditions, and, second, abnormal conditions.

In the normal condition, the hazard would be expected to be present in everyday production operations or during frequent repair and maintenance activity.

When the hazardous material is expected to be confined within closed containers or closed systems and will be present only through accidental rupture, breakage or unusual faulty operation, the situation could be called “abnormal.”

The Code writers have designated these two kinds of conditions very simply, as Division 1 – normal and Division 2 – abnormal. Class I, Class II and Class III hazardous locations can be either Division 1 or Division 2.

Good examples of Class I, Division 1 locations would be the areas near open dome loading facilities or adjacent to relief valves in a petroleum refinery, because the hazardous material would be present during normal plant operations.

Closed storage drums containing flammable liquids in an inside storage room would not normally allow the hazardous vapors to escape into the atmosphere. But, what happens if one of the containers is leaking? You’ve got a Division 2 -abnormal – condition . . . a Class I, Division 2 hazardous location.

So far we’ve covered the three types of hazardous locations:

Class I – gas or vapor
Class II – dust, and
Class III – fibers and flyings

And secondly, kinds of conditions:

Division 1 – normal conditions, and
Division 2 – abnormal conditions

Summary of Class I, II, III Hazardous Locations

Classes

Groups

Divisions

1

2

I Gases, Vapors, and Liquids (Art. 501) A: Acetylene

 

B: Hydrogen, etc.

C: Ether, etc.

D: Hydrocarbons, fuels, solvents, etc.

Normally explosive and hazardous Not normally present in an explosive concentration (but may accidentally exist)

The best way to go about this is to install the SVE equipment in a separate room from the air sparge equipment. We could build a vapor barrier wall inside of the container. That way the air sparge equipment and control panel won’t have to be XP (saves money).

This manager was able to convince the engineer and the specs were changed and sent to us and our competition for bids. We don’t know who won the bid yet or if any of the other bidders noticed the errors.

You could say that these were simple mistakes and have nothing to do with State government control on the purse strings. I have been in the industry for 34 years and would have to disagree. The “LOW BID GETS IT” approach has caused a drastic decrease in quality of work.

Brian E Chew Sr. P.G.
Principal Hydrogeologist

Comments

Robert J May PE, PG August 4, 2014 - 6:59pm

Robert J May PE, PG's picture

I would just like to give another perspective. My background is from working in explosive dust and astmospheres in underground coal mining, and I was a MSHA certified electrician.

The explosive range of gasoline is 14,000 to 76,000 ppm.

In underground coal mining, the continuous methane detectors alarm at 1% methane and shut off power to the equipment at 2%. The explosive range of menthan is 5-15%.

So based on a pilot test which a SVE system design has numerous extraction wells, one can certainly have a system where the highest range of vapors is below 40% LEL, the lower explosive limit.

I also have a long career as remediation design engineer and find more cases for non XP (explosive proof) criteria than for sites requiring XP equipment.

Just for a rule of thumb, if the design requires XP than the SVE air discharge should not be GAC (granular activated carbon) and the off gas treatment should have some type of thermal oxidizer.

I understand your concern for assembling equipment to a spec where the design is flawed, and that is certainly is your risk management.

But for those on this forum to now believe most UST remediation SVE -AS designs require XP equipment from reading your post, I respectively disagree with your comments.

Brian Chew August 25, 2014 - 6:39pm

Brian Chew's picture

Robert, Thank you for your comment. I would have responded sooner but your comment was caught by the spam filter. The intent of this blog post was not to say all SVE-AS designs need to be XP. A lot of these systems are not. The site mentioned, which required third party labeling, needed to be. I was more trying to emphasize the flawed designs and the need for more training and less copy-paste when it comes to designing systems. As to off gas controls, I have had systems in many States and unfortunately not many required any controls. The laws may be on the books but they are not enforced.

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