Where are the best opportunities in the field of process control?
I completed a 2-year Industrial Instrumentation program in 1986 and then became an operator at an oil refinery later that year. I worked as an operator for 12 years and then started in the process control department of the refinery in 1999 – where I still work (I also have a science degree). An opportunity is now available to work in the instrumentations department, which involves a training program similar to the one I took in 1984-1986. I am not presently a journeymen technician, however, this new opportunity would lead to that. What do you believe offers the best future in the industry, continuing my work in process control, or becoming a registered field technician?
I believe the opportunities will be greater
where you’re at in process control. As instrumentation has become more digital, and therefore smarter, the need for the special skills of the instrument field technician, at least as they've been traditionally known, has diminished and will continue to do so. I find more and more that this just seems to be added to the responsibilities of process control personnel, process and operations people.
Carlos Smith, Ph.D., Associate Dean of Academics, University of South Florida
You need to determine the lifestyle you want. You will likely make more money as a technician, but will be subjected to working in the elements, rather than as an engineer at a desk. I recommend you get your journeyman ticket and then you will have the option of pursuing whichever path you choose.
Ian Verhappen, Syncrude Canada Ltd.
Both positions can be very rewarding. I have seen a number of control technicians (and operators) move into process controls departments, but not the other way around. As a member of a process controls team/department for the past 10 years, I have seen many opportunities that build on the knowledge of a control technician position. And if you’re looking for a job with a quickly expanding description that contains ever changing opportunities, I would recommend the process controls position.
Scott Clark, Senior Engineer, Automation & Information Services
There might be more job security at the technician level, but if the person is interested in how well the instruments, valves, and controllers play together to make a product efficiently, I would suggest becoming a Certified Automation Professional (CAP). The Instrumentation, Systems, and Automation (ISA) Society has developed a CAP study and certification program that includes a study guide and a series of books. As you can imagine the material is quite diverse so I would pick one area to specialize in such as continuous improvement. Here you will need to learn about process interactions and relationships. For me, besides learning the fundamentals of process control, building dynamic simulations, reviewing process trends, and talking to the operators was the key to finding opportunities and dealing with practical problems. New tools have advanced the art of simulation, analysis, tuning, and advanced control. If you can make the operator's job easier and make money for the company, you become a valuable asset. However, the people who make these decisions may not recognize these opportunities. Demos targeted to the areas of interest using dynamic simulations and new control capabilities that show the financial gain online impresses key management because they can see it in action and shows the bottom line. It becomes real. If this is followed by a successful application, the door is open. In my case, my normal job as an instrument design and construction engineer for the first seven years of my career didn't require any of this as part of the job, so I did it on my own time. People are usually open to new ideas especially if they don't have to put any money up front. Some people took notice and offered me a job working in Engineering Technology, and the rest is history.
Valve-position Control with an External Reset Feedback.
I am interested in the loop diagram you showed for the VPC controller you described in The Hard Road to Our Competitive Edge—Part 1
. The VPC-2 shows two dotted lines into the controller, one from the valve position selector (obviously the PV) and one from PT-01.The VPC-2 set point is shown as 90%. What is the function of the line from PT-01? I have an experiment in my control class that I want to modify to demonstrate to my students this energy saving concept. We have a DeltaV system here in the lab and that signal is called "backcalculate." By the way, the savings using that system are great. I just roughed some $3400 per year if you went, for 1000 GPM, from 20 to 10 psig, lowering the speed, HP from 16.2 to 7.4, I used a Durco pump select program.
Robert L. Heider, Adjunct Professor, Chemical Engineering Department, Washington University, St. Louis.
Floating-pressure control is achieved
by using a valve-position controller to drive the control valve to an economically desirable position such as 90-percent open, by manipulating the set point of the pressure controller. This forms a cascade system with the VPC as the primary controller, as it has a fixed set point. However, pressure is the more important variable, in that it must be controlled, whereas valve position is simply optimized.
To minimize upsets to the pressure loop—especially where there are multiple valves in the system, from which one is selected for control—the VPC should not have proportional action. Integral-only control is recommended, with the integral time set relatively long, compared to the integral time of the pressure controller. Additionally, the VPC does not require access by the operator for startup or emergency operation—in fact, it can be a blind controller. The operator can override its action at any time by placing the pressure controller in local set or in manual.
To prevent windup of the VPC when its loop is opened, external-reset feedback is recommended. Positional PI control algorithms calculate output from deviation multiplied by proportional gain, plus a reset-feedback term, which is normally the controller output lagged by the integral time constant. When the control loop is open, this positive feedback causes integral windup. Primary-controller windup can be prevented in a cascade system by taking its reset-feedback from the secondary controlled variable rather than from the primary controller output (which is the secondary set point). In this way, opening of the pressure-control loop also opens the reset-feedback loop, thereby preventing primary windup. It also delays primary integration by the response of the secondary loop, but this is favorable, and even adapts primary integration for any variation in secondary-loop dynamics. Recognize that the secondary controller must have the integral mode, because any secondary-loop offset will cause primary-loop offset.
Some controllers use a back-calculation of the integral-feedback term to prevent windup when the secondary loop is open. While this does prevent windup, it does not provide the smooth transition of the integral time constant, and can result in erratic behavior and even offset under noisy conditions.
F. Greg Shinskey, Process Control Consultant, North Sandwich, New Hampshire.
Measurement Problems on a High Level
"We have a level measurement problem with a differential pressure (DP) level transmitter that doesn't seem to track level properly. The vessel is a glass lined reactor, with an internal agitator and baffles. The only other available opening is a 1-in. port on the top of the vessel. The vessel is 60-in. in diameter and 12-ft. high. There are cooling coils filled with Dowtherm, and a glass-wool-and-aluminum-lag insulating jacket that is about 6 in. thick. We are having real problems on high level, and the process upsets if the vessel is too full.
You have not described the type
of differential pressure level transmitter used, its elevation, the level range which should be detected, the filled or dry nature of the reference leg, or the locations of the d/p pressure taps on the reactor; therefore, one can only speculate:
The top connection of the d/p transmitter must be above the maximum level ever expected to occur in the reactor. To be on the safe side, it is best to connect it to the vent line on top of the reactor.
If you have a dry leg application, the problem can be with the range elevation adjustment. In case of a wet leg application, the source of the problem can be the range depression setting.
If it is possible that the reactor contents can boil, the use of a DP transmitter is the wrong level detector selection. This is because it detects the weight and not the height of the liquid column. The two will coincide only if the liquid density is constant. Therefore, it is possible that, during a boiling episode, the bubbles will cause the liquid density to drop and the DP cell will indicate a low level, when in fact the level is high and the liquid is boiling over.
If agitation causes the d/p measurement to cycle, this pressure cycling needs to be averaged. This is likely to occur at all levels, not only at high ones.
If the DP measurement is OK at all levels except high ones, and all you need is an alarm or interlock actuation when the level reaches some maximum, than you can use the 1 in. connection on the top of the reactor to insert a high level probe into the reactor. If the reactor contents are conductive, you can use a conductivity probe. If the contents are nonconductive, a capacitance probe can be used.
When the reading is incorrect at high levels, the level transmitter span or Upper Range Value is likely in error. The transmitter span may be calibrated 0-100-in. H2O. 100-in. is the URV. A DP transmitter used as a level transmitter needs the span or URV calculated. The URV is the height of the actual level measurement multiplied by the liquid specific gravity (SG). If the desired measurement is 100-in. high and the SG was 0.8, then the URV would be 80-in. H2O. If your SG used in the current calculation is 0.9 and the actual SG is 0.8, then a URV of 90-in. H2O is actually 80-in. H2O. This error would cause the level indication to read lower than the true level. At full level, the DP would actually be 80-in. H2O, but because the transmitter is calibrated for 90-in. H2O, the transmitter would send a signal of 89% and might cause an overflow. Best course? Measure the liquid's SG and recalculate transmitter calibration. If the transmitter is not located at the same height as the bottom tap, then the Lower Range Value will not be 0-in. H2O and will also need recalculation. If the SG varies, and you want to always read a level that is higher than the actual level, then use the lowest SG in your calculations. If the SG varies a lot, try using the more accurate level reading from a good radar level transmitter which measures the real height of the liquid and is not affected by changing SG.
Brian Smith, NOVA Chemicals (Canada) Ltd.
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