I have been trying to simulate a distillation column to separate butanol and water. The bottom product should be high purity butanol (>90%), I am able to match the composition, but I couldn't match the operating temp at the bottom (approx. 120 C, the temp indicator is at the column bottom with a meter of liquid above it). In my simulation the bottom product temp it gives is around 110 C.

All I can think of now is that the difference could be caused by the static head above the temperature indicator causing a higher bubble point at the bottom of the liquid sump. Can someone please confirm, or if you have experienced something similar, please share.

Thank you!

He will be missed.  Rest in peace, Steve.

1. Does this refer to the pipe outer-wall temperature or the actual bulk fluid temperature? Does maintaining the pipe wall at 35°C ensure that the fluid remains at this temperature?
2. As the gas flows, it may cool due to ambient heat losses and the Joule–Thomson effect as pressure decreases. Can heat tracing prevent water condensation under these conditions, considering that the dew point also changes with pressure? Would additional tracing duty or a temperature margin above the dew point be required?
3. Is tracing for temperature maintenance primarily intended to keep stagnant fluid warm when flow stops, or is it also designed to maintain fluid temperature during continuous flow?
4. What triggers the tracing to operate? Is it typically controlled by a sensor on the pipe wall beneath the insulation? How does this differ for self-regulating tracing?

As per the PFDs, a mixture of sour water and 50% hydrocarbons enters a three-phase separator operating at 185 psig and 120°F. The separator is provided with an LCV to control the liquid level. This LCV also reduces the pressure of the sour water from 185 psig to atmospheric pressure.

After separation, the sour water, containing 0.12 mol% H₂S, is routed to an atmospheric storage tank (internal floating roof tank) through an 8-inch line. The tank is provided with an 8-inch water inlet nozzle, which is submerged below the liquid level. The minimum tank liquid level is 4 meters, while the tank is 18 meters high and 15 meters in diameter.

The tank is equipped with a PVRV designed for thermal breathing. An H₂S adsorbent bed is installed on the tank vent line to treat the vented vapor before discharge to the atmosphere. The tank is also provided with nitrogen blanketing to maintain the required tank pressure.

The tank is an internal floating roof tank. The design sour water flow rate is 6,000 bbl/day, while the actual operating flow rate is approximately 2,000 bbl/day.

Appreciate any major concerns with this design. The project is about to start based on the provided design by the engineering contractor.

The curve may still be perfectly useful, but you're left with a scanned or paper Q-H curve rather than a digital dataset.

Curious how others here deal with this:

• Do you digitize the curve manually and recreate the Q-H data in Excel or another tool?

• How do you handle interpolation between the published points?

• When the operating conditions change, how do you generate a revised curve using speed or impeller diameter changes?

• For old curves, how do you handle efficiency and NPSHr data when only the original plotted curves are available?

• For pumps in series or parallel, do you digitize and combine the curves yourself?

I've ended up building an Excel workbook for my own work that takes a pump performance curve from a paper/PDF/image source, converts it into a usable digital curve, and then allows the curve to be evaluated under changed operating conditions using the relevant scaling relationships. It also allows the resulting performance data to be generated in a usable engineering format.

The reason I built it was mainly to make older or otherwise inaccessible pump curves usable again — particularly where the original OEM digital selection software or product database is no longer available.

Happy to share what I developed if anyone is interested. I'm mainly interested in how others here approach this problem and whether there are established methods or tools that you use.

I am sizing a PSV attached to a TEG filter, where the selected overpressure scenario is Fire Case. There are several heat and material balance (HMB) cases, which have varying operating conditions and fluid properties. Just for the sake of comparing I have run all cases with the reference stream taken at the inlet of my vessel. The results are as follows. My question is, how would I know how to screen for the HMB cases in order to get the maximum relief load and/or orifice area? By the trend in the table below, it seems that the maximum relief occurs with the case which has the highest overall MW and highest liquid fraction. Is this always the case? Are there any other fluid properties which I must look for in order to determine the governing HMB case?

 Hydrate_Prediction_Calculator_Wayne Gajadhar.xlsx   128.5KB   14 downloads