Try the following threads
thread469-65744  
thread378-49923

Good luck

Cheers,
Joerd

Please see FAQ731-376 for tips on how to make the best use of Eng-Tips.

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.

I agree witj Ashereng

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.

Best regards

Morten

If -by chance- you are interested in Viscosity-Gravity Constants (VGC) have a look at ASTM D2501-91 (2005).

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.

watwarrior,

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

From a 13 year old ASTM Manual on significance of tests for petroleum products

                                     Gravity_60F     SUS at 100^oF   SUS at 77^oF

Nigerian Light                    38.1                35.7              38.4      
Texas Gulf Coast mix          36.5                37.3              41.0
Redwater (Canada)            34.9                41.7              47.8
Lagomar (Venezuela)         30.7                64.3            107.0

Ashereng, can you work out a correlation ?

Ashereng

 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.

25362,

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.

Is this what you mean?

Sorry! I meant to put the question to watwarrior.

To ashereng:

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.

25362,

Ahhh yes. Saybolt Universal Seconds. Thanks.

I typically only use cP.

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 http://www.viscoanalyser.com/xls.html for these calculations but try and get your lab to give you the two temperatures as far apart as possible.

JMW
www.ViscoAnalyser.com

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.

Depending on the system pressure watwarrior may find that at higher temperatures the flow is in a two-phase V/L régime.

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 477^oF = 247^oC, as an upper limit, without giving info. on the pressure, thus one could assume vaporization.

A temperature of 300^oF, 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 ~350^oF 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.

The feed gets flashed when its about 200 C, so in all of the exchangers that im looking at, this is a completely liquid feed, all the way up to 247 C.

 And the pre-flash was a later addition to the plant, and was fit into an area were there is space, that is why it was put so late in the pre-heat stage.

 But the crude that im tracking will stay liquid, the temperature and the SG are the only things which will change.

All,

For what it’s worth Ashereng is absolutely correct.  Oil gravity is a method to calculate the specific gravity of the oil and nothing else.  Viscosity must be tested.  It needs to be tested at the very least at two points.  Without this test you could very well have a non-Newtonian liquid and not know it.

As a starting point Beggs & Robinson developed a formula for calculating dead oil based on gravity, but if you use it, it will get you in trouble sooner or later.

Beggs and Robinson dead oil viscosity in cP =

(10^(Temp in degree F^(-1.163)*EXP(6.9824-0.04658*API Gravity)))-1

If you actually test the oil you can use ASTM D341 standard to calculate the corrected viscosity at any temperature.

D23

watwarrior:

You indicated that you intend to estimate flow using pressure drop measurements in parallel pipes (the total flow before splitting having been metered).  However, you will have to be very careful about estimating the resistance of pipe fittings, valves, bends, etc. to obtain a reliable flow this way.  In my experience, estimating the resistance of partially open control valves is quite error prone.

Except in unusual situations, most pipeline flows are turbulent.  Also, on the Moody chart (for a given e/D ratio) the friction factor falls rapidly with Reynolds number, becoming independent of Reynolds number beyond a threshold value.  Then, the pressure drop is dependent only on liquid density, other things being equal.

A full range crude oil is generally hard to keep entirely in the liquid phase above 200 deg F, unless your line pressure is very high.  Hence, I would recommend a few flash calculations along the path to ensure that you are not running into 2-phase flow.  If you get 2-phase flow, it would be foolhardy to try to estimate the flow based on pressure drop measurements if pipe fittings offer a significant portion of the total resistance.

Further, did I understand correctly that you are pumping crude oil from 32 F all the way up to 477 F?  This seems an excessive range.  From where is your crude oil entering the system?

The Walther equation below is a useful relationship for viscosity v/s temperature for hydrocarbons, provided you don't have non-Newtonian behavior:

log(log(kv + C)) = A + B*log(T)

where kv is the oil kinematic viscosity (cS), and
T is the temperature (F), and A, B, C are constants found by regression.  This can easily be done using the Excel Solver, provided you have at least three measurements.

NOTE 1: All logs are to base 10.

NOTE 2: Obviously, (kv + C) cannot be less than 1, so you must ensure that the range of C is restricted by the lowest viscosity from your data.  E.g., if the lowest viscosity in your data is 0.3 cS, C cannot be less than 0.7.  In most cases, one may assume C is 0.8 and then use two viscosities to get A and B.

As others have noted, it is not feasible to estimate crude viscosity even crudely (pardon the pun) from density data alone.  However, it would seem to me that accurate knowledge of viscosity is unlikely to be critically important when your main interest is in estimating flow in pipe segments.

We pump the oil from a tank that is at ambient conditions. which right now can be anywhere from -10 to 10 deg C. and the process is suppossed to bring the oil up to about 248 deg C, before it goes into the heaters.

 This is all done using the products off of the distil. tower, so we dont have to spend as much money burning fuel to heat the crude to the point that it will give us the products we are looking for.

 As for the valves, unless the exchangers are off line, the valves are wide open, and i have been provided with pressure drop curves over the valves relative to flow, density and viscosity of the fluid.

Good point from UmeshMarthur,
the spreadsheet I gave the link to is for viscosities above 2cst:
log10.log10(v+0.7)=A-B.log10.(T+273)
where v is kinematic viscosity in CST and T is temperature in degrees C.
For lower viscosities the number of "constants" increases to 3 or even 4.
Note, The spreadsheet uses log10 though I have had a comment that it should be logn i.e. Naperian rather than Briggs. Without a copy of the ASTM D341 standard to hand I can't verify which is correct though it would appear that log10 is consistent with the Walther Equation provided by UmeshMarthur.
Anyone know for sure?

JMW
www.ViscoAnalyser.com

Watwarrior,
I was interested in D23's comment on the Beggs Robinson equation and did a search.
Just on the first page came some very interesting links which you might wish to follow up:

http://www.energyconnect.com/pttc/archive/bergmanviscosity.pdf
http://www.unicous.com/oilgas/fuelcalc.php
(also see the home page for a discussion)
http://www.unicous.com/oilgas/corrcalc.php
(this appears to be an online calculator doing what you originally asked)
http://www.ripi.ir/en/congress11/the%20best%20equation.pdf

The two pdf files were most interesting.

JMW
www.ViscoAnalyser.com

jmw,

I did a quick scan of the 2 pdf files in your post.

WOW!   and thanks for the links (Star for you.)

It seems that a lot of scientists went to a lot of trouble to try to develop the correlations for their fields crude oils (and within fields as the HC distribution changes).


watwarrior,

In order to develop the correlations that I think you are thinking of, this is the level of empirical data collection and development required to get a useful set of equations/charts.

Haveing said that, the authors of these studies are looking at a very large range, I am hoping that your range of interest can be localised (for example, my appliations is limit to 3 temperature points, and within a very narrow range at that), then the level of work can be simplified.

Often times, we can make simplifying assumptions on lots of things since the uncertainty in another part of the overall "problem" may overshadown, in this case, your viscosity uncertainty.

Hope this helps.

All,

Please remember that the oil API is a method for calculating the specific gravity only.  There is not any relation between specific gravity and viscosity.  Any correlation you use can only be a starting point.  Testing the oil is the only way to know the viscosity.

As a example I looked at a well several months ago where the oil API was 12.4 and the bottom hole temperature was about 100 degree F.  If I calculated using Beggs the dead oil viscosity should have been about 715 cP.  The actual test at 100 degree F was over 2700 cP.  Designing lift required and friction losses using calculations verses actual test can result in a catastrophic error.  

The ASTM formula for calculating viscosity at different temperatures does not account for pressure.  
 
V = [log.log.(v+07)=a-b.log(t+273)]

If the produced liquid is non-Newtonian this formula will not work.  

As others have already noted, the units of temperature in the Walther equation should be absolute [K] or [R], rather than [C] or [F].  Otherwise, one woukld get log errors below 0 degrees.

In response to JMW's question, I'm pretty sure (from work in grad school in the 1970s) that the original form of the Walther equation required use of logarithms to base 10.  Of course, if one selected Naperian logs, one would get numerically different coefficients but the statistical fit would be equally accurate.

The reference I have is:

C. Walther, Proc.World Petrol.Congress 2, 419 – 421 (1933)

Thanks UmeshMathur.

Incidentally I have noted that in several learned articles the equation is quoted without showing the base for the logs and that they also define T as temperature without stating the units.

This is really poor practice and to be deplored.
I will start by putting myself on the list of guilty parties for my own omission of the base for the logs on the ASTM D341 spreadsheet I referenced above.
(I'd better correct this.)

JMW
www.ViscoAnalyser.com

d23:

Two points regarding your post:

(1) Crude oil behavior is generally pretty close to Newtonian
(2) The effect of pressure on liquid viscosity is significant only at very high pressures (thousands of psi, typically).  Correlations in the API Technical Data Book demonstrate this pretty clearly.

I would think that watwarrier's application (preheating using crude oil from tankage) is unlikely to be at high pressures on the crude oil side.

Once again, I think we are straying a bit from the issue raised by watwarrier's original problem:  is the Reynolds number high enough for viscosity to be a factor in pressure drop or not?  At very low temperatures (around 32 F), it is quite likely that the oil is so viscous that Reynolds number drops drastically, since viscosity increases dramatically at low temperatures (by virtue of the log-log relationship), and the friction factor needs to be evaluated below the transition to full turbulence.

Therefore, as others have mentioned, there seems to me to be no way around a couple of decent viscosity measurements in this situation.

UmeshMathur, Your last statement got me thinking to one of my intern jobs.

Most companies have physical data of the materials they use. Actually, they have stuff no one would think of. For example, I needed to estimate heat loss in a particular tank (complete through insulation, etc.) Now I admint, I am not the best guy at heat transfer calcs, so I asked around, and sure enough, there was a set of binders with heat loss empirical data for each and every tank on site. My classmate in a different department evidently had the same task assigned as well, and did the calcs from estimates and first principles. We compared answers, and were off by about 5%-10%, depending on surface size.


Watwarrior, have you asked around to see if the viscosity data you need is already available somewhere?

The oil is flowing through these pipes at 900 k#/hr, which makes this flow extremely turbulent (8" - 16" pipes).

 And unfortunately, the previous people who have tried this, assumed that the viscosity of crude was constant over the temperature range, and used the old values (from early 70s) that were used as rough estimates to size the first exchanger in the sysem.

Oh. Well, it was worth a thought.