This Month’s Puzzler
A few years ago, we increased the capacity of our batch reactor to 1,900 gal. from 1,200 gal. Our process produces about 364 BTU/lb of heat, so the cooling requirements went up about 1.5 MM BTU/hr. In addition, heating (with low-pressure steam/water) rose by 245,000 BTU/hr.
Our quality engineer, in league with our control engineer, found that operators manually manipulate the steam and cooling water control valves to manage the temperatures. We’ve suffered 18% more temperature excursions where the operator lost control of the process for several minutes; off-product is up 2% but we’re not having trouble blending out the reject.
Now, our safety manager is involved because we risk operation above the flash point of a monomer product. Corporate engineering, which managed the expansion project, claims that nobody at the plant mentioned this during the hazard and operability assessment. However, corporate quality control doesn’t see an issue. The production manager says his crew can manage the reactor safely. (I think he’d rather spend next year’s budget on items other than expanding the steam and cooling water system.) What do you think? Why didn’t we catch this during the expansion? Can we justify utility improvements as quality improvements if the production group is managing the problem? Is there any real risk from these temperature excursions?
Triple-Down Your Efforts
There are three key issues in the problem:
1. Operators’ general inclination to run the control in “manual.” Because no details are given about the transmitters for steam or cooling flow and no information about the type of control (e.g., split-range, selective or other), consider the following broad suggestions:
• Talk to the operators to find out the cause(s) of their apparent reluctance to use controls in automatic. Reasons could be diverse, e.g., a clogged or out-of-calibration cooling water meter, impulse lines on steam meters interfering with the meter response, etc.
• Also, closely related to transmitter problems, control valves may be too fast or too sluggish. These may need tuning. Sluggish valve behavior can arise, for example, from stem packing that is too tight or deposits in the bonnet area.
• Many batch controls use split-range temperature control; you may need to look into tuning.
• Try to identify problems and correct them without a massive change of all meters and controls.
2. Temperature fluctuations. Although minor fluctuations in temperature are to be expected, major fluctuations could be a problem. The threshold as to when a fluctuation is major depends on the material of construction and frequency of fluctuations. Some materials such as brazed aluminum (used in the liquefied natural gas industry, for instance) are very susceptible to damage when fluctuations exceed 3–4°F/minute. For many services using shell-and-tube exchangers, opting for U-tube and floating-head designs would help in handling thermal expansion. You should check with vendors of the components of the system that experience thermal fluctuations. If you have determined that temperature excursions are a major issue — and they could be during either the heating or cooling phase of operations — consider providing rate-of-temperature-rise alarms.
3. Flash point. Consider safeguards if operation can reach the flash point. These include: a blanket of inert gas, grounding, explosion-proof equipment, electric area classification (API-500), submerged loading, fire-and-gas detectors and alarm systems, fire protection systems, and system isolation.
In the long run, maintain contact and build rapport with operations and maintenance and help resolve their problems expeditiously. Keep them informed of changes you plan to make. Get their buy-in.
GC Shah, senior advisor
Wood Group, Houston
Focus On Quality
Being a stickler for quality, I am bit surprised that less-than-acceptable-quality material is being blended and money is being spent on that effort rather than fixing the underlying issue. Blending the material to ensure no off-spec material is shipped is essentially lowering the profits.
I would spend the necessary monies to address the issue of temperature controls. Investment here would pay off in peace of mind and no worries about quality. If the plant marginalizes quality by blending off-spec material, I wonder what else it does.
Girish Malhotra, president
EPCOT International, Pepper Pike, Ohio
Address HAZOP Failings
The reason why hazard and operability assessments (HAZOPs) are done in the beginning, middle and end of a design process is to capture errors that accumulated during the process. This also is the reason why you should conduct safety reviews after construction: to clear out the mistakes made interpreting the design.
Obviously, the increase in capacity wasn’t properly reviewed or there would be fewer surprises. You should perform a full-blown HAZOP periodically: a “what if “ analysis, for well-known systems, allows you to identify and address critical problems. I doubt if 2% rejects is a quality problem but safe operation is an issue.
Right now, what’s saving you from a major accident are the highly skilled operators managing the reactor temperature. It only takes a junior operator a few hours on a third shift, at the end of a crushing double-shift, to cause a significant incident.
Generally, mixing is at the heart of many temperature control problems. You may be able to reduce the lag in the temperature measurement by improving agitation and locating the instrument where velocities are high but also representative of the reactor temperature. As for the control element, consider an electric actuator to get more precise control. You also may want to consider split control so that you use a larger valve when heating/cooling demand is high and a smaller valve at the end of the reaction when demand is light.
Dirk Willard, consultant
Wooster, Ohio
May’s Puzzler
Our sulfuric acid tank is corroded and leaking, a problem made even worse because our plant is located in a swamp next to wet lands of a major river. We’re desperate because the inspectors give us two years and we are squeezed against a creek. The only economically viable location is 100 ft from the creek. I am proposing a 12-ft diameter, 50,000-gal. double-walled storage tank without a diked-in containment area as the replacement. Corporate is concerned about not having a containment area. However, water bubbles out of the ground in our current diked areas. Moreover, a typical secondary containment area only lasts about 30 years before pipe suction lines buckle because the pumps are mounted on the area floors; we’ve tried re-lining dike floors without much success.
I’m proposing a simple pad for the pumps and heat exchangers, and another pad for the tank; the equipment pad will be connected to the tank pad by an expansion joint. Will this pass the regulators? Is a double-walled tank a better solution than a single-walled tank and secondary containment?
Send us your comments, suggestions or solutions for this question by April 9, 2020. We’ll include as many of them as possible in the May 2020 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.
And, of course, if you have a process problem you’d like to pose to our readers, send it along and we’ll be pleased to consider it for publication.
