Perspectives: Process Puzzler
Ensure a Satisfactory Steam System
Readers suggest ways to improve steam operations
THIS MONTH’S PUZZLER
We’re expanding our plant and are planning to add two heaters to our steam system, which sometimes can barely keep up with demand as it is now. Figure 1 shows a rough sketch of the process flow with the steam usage from the data sheets. The plant barometric pressure is 14.66 psia. I’m concerned the new loads will be too much for our steam piping. Our plant superintendent feels the boiler makeup water pump is a limitation. How should we upgrade the steam system?
CHECK VARIOUS THINGS
Here are a few items to look at to minimize the impact of the added load: 1) Are there any heat efficiency opportunities? 2) Are all the steam let-downs really needed? 3) Could any of the heat loads be converted to another source? 4) If de-superheating stations are not used downstream of let-downs, consider the incremental steam from lower-pressure de-superheating water and taking advantage of the potentially less efficient superheated steam vs. condensed. And, finally, 5) there is the loss of steam to poor maintenance of steam traps, leaks and poor or insufficient insulation that will increase the water make-up.
Heat efficiency requires surveys. Are there some hot overhead or product process steams that are being cooled by air or water that could be cross-exchanged with feed or the inlet streams to the steam-heated exchangers shown to minimize the amount of steam usage?
Let-downs are often a problem. Could the process take higher steam temperature and allow the 50-psi steam to go to 100 psi? Or, why not let down the outlet of the 450-psi boiler — thus allowing for denser steam and less pressure drop per pound of steam used? It doesn’t look like there are any turbines or machine loads where close pressure control is needed. Also ensure that pipe runs around let-down stations are as close to the source as possible.
Lastly, steam may not be the best heat source for an operation. Perhaps the dryers could be gas-fired or use electrically heated air or nitrogen as opposed to the large amounts of steam.
Tom Brader, staff instrument engineer,
Valero, St. Charles, La.
LOOK AT THE MAKE-UP PUMP
Consider the following: 1) As shown on Figure 1 (rough sketch), the additional load (pressure at 50 psig) from the proposed equipment is less than 5% of the current load on the system. Check if steam traps are working properly. Check for steam leaks. Do an audit of the traps. 2) No data are provided on the design capacity of the boiler relative to the actual load. Is the boiler under-designed for the current load? Check thermal efficiency of the boiler. Improved efficiency could help mitigate the current strain on the system. 3) Do a visual survey of all heating equipment and piping. Look for damaged insulation and fix any found. And 4) the problem statement does not have data on the boiler feed-water pump relative to the boiler capacity. However, you may look into enlarging its impeller, if there is enough net positive suction head to support the larger impeller.
GC Shah, senior advisor,
Mustang Engineering, Houston
GET SOME MEANINGFUL DATA
Based on a cursory review of the steam header and branches, I don’t see a problem with the steam system. A look at the condensation system shows three open vents — the dryers and one of the heat exchangers — that allow the operators to bypass the condensate recovery system. Bypassing the steam traps means that additional makeup water is required.
So, I started by using boiler set pressure, 450 psig, and assuming saturation. If we assume an isenthalpic throttling through the pressure reducing valves (PRVs), we get a latent heat of about 773 Btu/lb — that’s the enthalpy of saturated steam at 450 psig. Dividing by the loads, I got dryer loads of 15,524 lb/h for 12,000,000 Btu/h and 10,349 lb/h for 8,000,000 Btu/h. Converting to boiler water, I estimate 54.4 gal/min (Q = lb/h/(500.236×SG), for a specific gravity of 0.95 at 240°F, with saturated steam at 10 psig in the deaerator, and 60°F and 14.696 psia assumed for reference). The sum of the current steam load divided by 773 shows about 64 gal/min of boiler water in circulation. Take that out of circulation by venting it or dumping it to the sewer and the makeup-water pump can’t keep up. Now, let’s move on to the expansion work.
I used the charts and tables on pages 5-33 through 5-37 of “Cameron Hydraulic Data Book,” 19th ed., to evaluate the pressure drops in the steam header and branches. Initially, I used a table in the Plant Notebook section of the April 7, 1980, issue of Chemical Engineering that was contributed by S.C. Nangia: pressure drop must be < 0.1×operating pressure/ft for headers and <0.2×operating pressure/ft for branches; a direct comparison is better. I came up with an 8-psi loss in the 2,000-ft, 3-in. pipe after the nearest upstream PRV set at 50 psig. Using the table in Cameron, pp. 5-34–5-35, to correct for ½ psig from the chart, divide the total flow in the pipe, 1,423 lb/h, by 1.943 for 50 psig (= 732 lb/h in the chart); look up the pressure loss per foot (0.004 psi) and multiply by 2,000 ft (= 8 psi). This is too high. My recommendation is to increase the set pressure to 75 psig. I calculated 5.6 psig with a coefficient of 2.297 from pp. 5-34–5-35. If the set pressure is a problem for the equipment ratings downstream, raise the pressure even higher for the header PRVs to reduce pressure loss, and add PRVs downstream to protect the equipment.
There is one more thing to consider: where did these heat loads come from? If they’re from exchanger data sheets, then they are some project engineer’s concept of reality. You need to get data on steam usage by measuring steam condensate and estimating boiler fuel consumption. Only then will you have a meaningful material balance. For additional information, try these websites: http://goo.gl/gCLMji; http://goo.gl/a0Vkek; and http://goo.gl/CAZhU2.
Another useful article is a May 12, 1986, contribution to Chemical Engineering’s Plant Notebook by Virgilio Ganzalez-Pozo: “Formulas Estimate Properties for Dry, Saturated Steam.”
Dirk Willard, consultant
We’re suffering an annoying thermal expansion problem in the ethylene oxide (EO) lines that feed our reactors: pressure relief valves (PRVs) often pop from solar heating, because lines are blocked in, typically for up to ten minutes. (Our design standard assumes horizontal pipe and a maximum ambient temperature of 95°F, which doesn’t occur very often at our Chicago site: solar flux is 38.7 Btu/h-ft2 for the summer solstice.) The PRVs wouldn’t be such a problem but EO can polymerize and cause them to stick open, which is why the covered area under the reactors is Class 1, Division 1, Group B. The EO feed pipe runs at 55 psig at 60°F. The PRVs are set at 145 psig. Barometric pressure is 14.408 psia. The properties of EO at operating conditions are: density, 66.8lb/ft3; viscosity, 0.302 cP; heat capacity, 0.476 BTU/lb-F; thermal conductivity, 0.0949 BTU/h-ft2-°R; volumetric thermal expansion coefficient, 0.001°F-1; and bulk modulus, 180,000 psi/ft3.
Our plant engineer is convinced that two inches of calcium silicate insulation in a stainless steel jacket over our 1½-in. Schedule-80 Type-316 stainless-steel pipe largely will eliminate our PRV reliability problem. What do you think?
Send us your comments, suggestions or solutions for this question by September 12, 2014. We’ll include as many of them as possible in the October 2014 issue and all on ChemicalProcessing.com. Send visuals — a sketch is fine. E-mail us at ProcessPuzzler@putman.net 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.
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