The second thread on there doesnt have much to offer me right now, but the equation in the first thread seemed good. But when i compared it to the values that i dug up ... the equation was way off.
Crude Oil @ 35 F with SG .85 (API 34.971)
By the equation it has a viscosity of 241 cP, but the info i looked up gave a viscosity of 9.2 cP. Just wondering if you, or anyone could explain this (giant) difference.
Crude oil is not a pure substance - ie. crude oil does not have a specific definition, like say O2.
Crude oil is a mixture of a whole bunch of HC, water, and other stuff.
The fact that 2 crude samples have the same density only means that they have the same density. The chemical properties of the 2 samples will most likely vary widely - like viscosity. Viscosity variability has more to do with composition than density/temperature.
In school, we had correlation charts for specific crudes. Even this is not reliable, a field usually has many wells, and also within a "well" it may vary from location to location, within the same formation.
In practice, any viscosity vs density/temperature will only be of use for the particular crude you are looking at.
In my industry, we take it to the lab and they measure it.
Viscosity is one of the most unreliable properties to determine by equations. HYSYS e.g. offers several correlations - and they are usually not correct. Since viscosity plays a major role in e.g. sizing of separators this can be critical.
All i need is something that will give me a close estimate to the viscosity. Im trying to determine flows in parrallel lines, but the only flow meter on the lines comes before the split into the lines. An estimate of the viscosity will help me determine the flows.
It would be misleading for me to tell you what viscosity equations/correlations to use. I don't use them myself unless I got the lab results back for my own samples.
If all you are doing is trying to figure out flow in parallel lines, and you have a total flow going in, you can base it on 50%-50% if the parallel lines are identical.
If not identical, you can base it on pressure drop estimates (must more reliable than guessing viscosity):
- measure lengths,
- measure diameters/schedule
- count fittings
- there are lots of equivalent length estimates for fittings that you can use to convert to pressure loss
I am using pressure drops to estimate the flow. But the equations require the use of Reynolds number, which requires the viscosity of the substance. Im starting to think that our lab is going to be getting a little more work soon. I might have them make a correlation on the crude and condensate that we use here, and base it off of that.
I am not sure what SUS is. I am not familiar with that acronym.
For what I do. As I am interested in 3 temperatures: 0°C, 5°C and 12°C. I have lab results on viscosity of my sample at these three points as minimum. I put them in Excel, plot them. Depending on what they look like, I chose between a linear, second, third or fourth order correlation.
Primarily, I use the lab results - as I said, I am primarily interested in 3 temperatures. If the temperature is too low, I will be cutting flow back anyways until things heat up. Things usually don't get too hot.
SUS means Saybolt Universal Seconds.
For values lower than 100 SUS, the old conversion to kinematic viscosity in centistokes is: cS = 0.226*SUS-195[÷]SUS
For values greater than 100 SUS, the old conversion to cS (=mm2/s) is:
cS = 0.22*SUS-135[÷]SUS
There are graphs (e.g. ASTM, BP) for KV vs T that would enable a straight-line extrapolation to a bit wider temperature range based on two points.
The list I presented is to give watwarrior an idea. I fully agree with you and MortenA on the futility of trying to find gravity-viscosity universal correlations for crude oils.
Im interested in a little bit of a larger temperauter range though. My temps go anywhere from 35 F to 477 F in the area im looking at. So my lab cant exactly give me the whole scale for me. If i use them im going to have to extrapolate the data to fit the curve to my temps.
The curve fit is achieved using ASTM D341 i.e. to compute the viscosity at target temp from the measured viscosity at two other temperatures.
Of course, you'll need to use centistokes (not centipoise) and degrees C for this.
You can download the spreadsheet at
I agree with jmw, it is usually better to interpolate than extrapolate (unfortunately, not always).
Try to get as many points at where you will be running though, in addition to the end points. I know that most labs are up to their white coats in back log, but...it will help.
By the way, that is a HUGE range 0°C - 250°C (32°F to 477°F). Can you share what you are doing flowing at such disparate temperatures? Just curious.
This is the preheat section of the an ethylene plant. The system does not go into two phases until after a flash drum, in which the temperature is somewhere around 200 C. We need the high temp to be able to 'distil' the naptha and 2 oil off of the crude.
To watwarrior, in a previous posting you mentioned 477oF = 247oC, as an upper limit, without giving info. on the pressure, thus one could assume vaporization.
A temperature of 300oF, i/o to reduce crude oils' viscosities (under a pressure sufficient to avoid vaporization), is regularly used for the efficient desalting of crudes.
A preheat temperature of ~350oF or more -midway in the heat exchanger train- is generally applied to the crude fed to a pre-flash tower with its pressure "floating" on the main fractionator pressure.
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