This Month’s Puzzler
My company has received an order to build a skid to make a mixed gel, an intermediate for a personal care product. The skid will include an agitated batch reactor where a powder is added to produce the viscous gel. This is pumped through a heat exchanger and then blended with a fragrance in a static mixer before going to an agitated storage tank. The skid boundaries were to end with feed to the storage tank but have expanded to include clean-in-place (CIP) and utilities skids; the customer insists this shouldn’t affect delivery. We’re having trouble defining boundaries between the skids and have received nothing more than some product properties, i.e., viscosity, density and heat capacity at a single temperature. What can we do to ensure this equipment works as desired?
The Delivery Date Will Change
The first part of the description of the situation presents as a classic scope control problem. Before making a proposal, the supplier should impose a requirement that the customer specifies boundaries for rates, physical properties, performance properties, and conditions. If they are not specified in advance, proposals should include a disclaimer that final schedule and cost depend upon buyer-approved boundary conditions.
If the additional skids don’t change the agreed conditions of the process skid, then the process skid delivery schedule shouldn’t change. If any part of the process skid scope changes, then delivery should be expected to change.
The classic client request when multiple skids are involved is to optimize the system to minimize investment or operating costs. Optimization implies that boundary conditions, or even equipment in the skids, can change. In this case, the client should expect delivery to change. Optimization takes time. Of course, clients don’t have to be reasonable.
The second issue is on physical properties. What you need to know depends upon processing conditions. Knowing just some of the product properties will make work difficult. At a minimum, you need to know some reaction properties, physical properties under mixing shear, and physical properties that vary with temperature.
The client may not even know the properties. A lot of work can be done with a willing assumption of some degree of technical risk and expense. Extrapolation may be cheaper and quicker than generating properties. At a minimum, this approach requires thorough documentation. Nevertheless, even guessing the properties and documenting them takes time.
Knowing how the client thinks is critical. Some clients, no matter what, will always blame you for anything that doesn’t work. You never should agree to anything but having the client completely define everything in this case. I’ve worked with this type; after negotiation the quote from the client was: “We can accept anything except an arithmetic error.” Other clients fully understand the risks involved. With this type, reasonable agreements on the way forward work well.
There’s no easy answer to your question. A lot of what your company agrees to depends upon management’s willingness to accept financial risk. In no case should unknown physical properties or desire to meet schedule be allowed to create safety, health or environmental (HSE) problems. If more time is needed for HSE, then take more time. If more information is needed for HSE, then insist upon it.
Andrew W. Sloley, principal engineer
CH2M HILL, Bellingham, Wash.
Keep Asking Questions
It will be very difficult to design the skid to the customer’s satisfaction without additional information. Put this in a memo during the bid. Some vendors will think they’re off the hook if they build precisely to the blueprints but that’s ridiculous; your company takes responsibility once you agree to build a skid.
There may be some sources to mine for your use. You can start with the material safety data sheets (MSDSs) but these usually are incomplete, rendering their usefulness doubtful. Most manufacturers don’t even bother to complete the safety portions of these vital sheets, labeling auto-ignition temperature (AIT), flash point (FP) and even normal boiling point (nBP) and vapor pressure (P*) as “N/A” or “not available.”
Other options exist. Ask the customer for contact information and a letter of introduction to its ingredient suppliers. They are required to identify fire risks if they ship a product. Another alternative is an independent laboratory. A fourth choice, which often is all that’s left, is checking textbooks and similar sources. This will be a challenge. A last option is referencing a similar compound. For example, cellulose acetate has a defined AIT and flash point in NFPA-30; cellulose ether doesn’t.
Given the nature of fragrances, I already know there’s a potential fire risk. In 1992, I identified in EPA documentation iso-amyl acetate, an ingredient in a fragrance we handled. Iso-amyl acetate has a flash point of 77°F and is a Class IC, “flammable liquid” according to NFPA-30. Obviously, this opens a can of worms.
As for identifying the fragrance for design purposes, you’re usually left with finding an analogous organic that has similar active groups (e.g., -OH, -COOH, etc.) and similar chain length — remember it must be a liquid at storage temperature! In one case, I found a “linalool” as a stand-in for a lavender fragrance.
The fragrance storage will require an emergency vent and conservation vent, which can be combined as one. Typical pressure settings for atmospheric tanks are slightly below 0.5 psig, in compliance with OSHA 1910.106(a) (2). The vacuum rating, from air in-flow, is below 0.5 oz/in2, in compliance with API- 2513 “Evaporation Loss in the Petroleum Industry.” The emergency vent setting based on external fire is higher than the air out-flow conservation setting. One vent I sized required a 4-in. inlet (refer to: http://goo.gl/CWt93u). Be careful to draw the boundary line for the skid at the exit of the conservation vent/emergency vent — you have no idea what the customer’s vent looks like, so size for the lowest pressure possible to provide ample vent pressure drop.
In addition to venting, you may need N2 blanketing to reduce fragrance losses and odors. An activated carbon bed likely will be required for the conservation vent. Typically, these vents are sized at a 1–2.5 psig set pressure with a flow of 8.021 times the tank pump-out rate in gpm: for 2 gpm withdrawal, that’s 16.04 std ft3/h of air (60°F, 1 atm) that must be replaced by N2. The lower the pressure setting, the lower the loss of N2 to the conservation vent. Here’s a useful white paper: http://goo.gl/eqPPgR.
Although the fragrances typically will be Class III rather than Class II under NFPA-30, there is a risk if they are heated, which could occur after the static mixer. OSHA 1910.106(a)(19)(iii) states that Class II or Class III liquids — these normally are ignored in Electrical Area Classification (EAC) studies — must be treated as Class I liquids, i.e., they may not be ignored, if heated within 30°F of their flash points.
Another problem is that fragrances are known to swell many commonly used gasket materials such as EPDM and some fluoroelastomers but not PTFE. It provides a good static seal against this type of material but performs poorly as a dynamic seal, like a valve stem seal. Limited materials are available because the gasket must meet stringent FDA requirements to ensure that gasket components don’t leach into foods and drugs. Some of the newer soft perfluoro-polymers perform well, and are FDA-approved, but may incur additional cost because valve and equipment manufacturers don’t have dies cut for them.
Lastly, remember the fragrance is a non-conducting organic. Everything must be bonded (connected together) and grounded after the fragrance is added to the product. Otherwise, you risk operators being shocked and a fire.
There’s another risk we haven’t considered: the powder. It poses an obvious hazard in handling and an insidious risk in mixing in the reactor. Organic powders generally can be classified under NEC-500 as Group G: classification depends on enclosure and housekeeping. Refer to NFPA-499, “Recommended Practice for the Classification of Combustible Dusts and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas.” The insidious risk comes from the potential vapor pressure produced by dissolving the powder in the reactor. Thanks to “N/A” on the MSDS, you’ll have a real challenge with that one. My suggestion is to keep the reactor and other tanks under vacuum — but take care where you vent them and how you handle activated carbon beds during disposal.
Dirk Willard, consultant
Our makeup-air heat exchangers seem to have suffered ruptured tubes. On the shell side, we use 45-psig steam reduced from 200-psi boilers. We send 40% propylene glycol/water through the tubes; at the steam control valve inlet with a 50% load it’s 42 psig. The exchangers are horizontal U-tubes with ¾-in. × 0.049-in. (16 BWG) copper tubes. The tubes were rolled into a 316L stainless steel tube sheet and sealed with fluorocarbon gaskets. Both exchangers are 24-in. diameter and 6-ft long. The exchangers are about 50% oversized sometimes while running about 105% during the winter months. We run one at a time. Another concern is that the tube-side relief valve was sized using the old 77% rule — is that okay? I think a classic case of water hammer causes the crushing of a number of tubes at the top of the tube bundle that we see. When we operate at only 50%, there’s a thermal reservoir in the shell that pulls a vacuum; another engineer believes that’s the culprit. What do you think?
Send us your comments, suggestions or solutions for this question by May 15, 2015. We’ll include as many of them as possible in the June 2015 issue and all on ChemicalProcessing.com. Send visuals — a sketch is fine. E-mail us at [email protected] or mail to Process Puzzler, Chemical Processing, 1501 E. Woodfield Rd., Suite 400N, Schaumburg, IL 60173. Fax: (630) 467-1120. Please include your name, title, location and company affiliation in the response.
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