Marko Asks PERM:
Hi,
I like your site very much and especially the Fundamentals of fluid flow paper.
I hope that you can answer me one question regarding the oil viscosity selection for the unsteady state relative permeability measurements at room conditions for the oil/water system. I heard that the general practice for the paraffinic oil viscosity that is supposed to be used in the test is to target the viscosity of a stock tank reservoir oil sample. In my case the stock tank oil is immobile at room temperature and thus it’s impossible to measure the viscosity. Someone suggested me to measure the viscosities at elevated temperatures and approximate the data for a room temperature but that doesn’t seem right to me because that is far away from the reservoir viscosity.
I was wondering if I know the right viscosity values of reservoir oil and water, can I use that ratio or match that exact viscosity values in the unsteady state test and that way get much closer to the real conditions in the reservoir.
So could you please tell me would you select the appropriate oil and water viscosities for the room conditions test?
Best regards,
Marko
Dr. Jonathan Bryan from PERM Answers:
Hello,
If I understand the question correctly, you are trying to run a steady-state relative permeability test, but in a viscous oil that you are having difficulty measuring viscosity for. Is your question how to do relative permeability modeling for this oil, or how to measure viscosity at reservoir conditions?
- First of all, let’s start with measurement of viscosity. If you are trying to get data for a relative permeability test, the key isn’t necessarily the stock tank oil viscosity at the reservoir temperature, but rather the actual (live oil?) viscosity at that condition. Because that is what is flowing in the reservoir. The advice you got about making measurements at higher temperatures and then extrapolating back is not bad, this is common practice followed. But I am confused about the part where you say that viscosity is immobile at room temperature, but you want to run a displacement test at that condition. First of all, do you mean that your reservoir is at room temperature? And second, if your oil is immobile at that condition, are you sure that you would want to run a displacement test there? What process would that be modeling?
- Now for the second part, about your unsteady state relative permeability test. Remember that when oil viscosity is much higher than water viscosity, you have significant viscous fingering of water through the oil, and bypassing of oil. So your results (oil recovery profile, water cuts) will be affected by the rate that you choose, and you need to choose something that makes sense for your system. Also, in the lab, you can generate much higher pressure gradients than what you could achieve in the field, which would also skew your data, so please be aware of this. Finally, in a system with oil viscosity >> water viscosity, you will get very early breakthroughs, fast climbing of water cuts up to greater than 95%, and then continued production of oil under high water cuts for many pore volumes of injection. So please be aware that the residual oil saturation that you measure is not the true (capillary) residual oil saturation, since if you just ran the test longer you would also get more oil out.
Have I misunderstood your question?
Dr. Jonathan Bryan
Marko Asks PERM:
Hi,
Thank you for a quick response. Obviously I didn’t make my question clear enough but I think you’ve already answered my question.
Anyway, I would like to know what viscosities of oil and water should I target for unsteady-state relative permeability test under the room conditions, what is the recommended practice for that transfer from reservoir to room pressure and temperature where there is no gas dissolved in the oil?
For this oil field of mine, I have the oil and water viscosities at reservoir pressure and temperature which are 8.5 and 0.56 cP respectively. If I prepare the synthetic water with the right salinity I get the viscosity value somewhere around 1 cP on room temperature. So what seems right to me is to take that 1 cP water and 15.2 cP (15.2=8.5/0.56) for the mineral oil viscosity, thus keeping the same viscosity ratio as it’s in the reservoir.
My colleague wanted to use 1 cP for synthetic water viscosity which is equal to the brine viscosity on room temperature but also wanted to match the viscosity of mineral oil for the unsteady-state test with the viscosity of the dead (stocktank) oil which would be around 100 cP. So that way you don’t get the water/oil viscosity ratio as it is in the reservoir and as you said, I would soon get water cut and Sor value too low.
Best regards,
Marko
Dr. Jonathan Bryan from PERM Answers:
Hello,
You are right to be concerned about this! If you think that your reservoir viscosity ratio is 15.2, but you are running at test with viscosity ratio of 100, then yes your results may not be correct. So probably your approach would be better. But also maybe consider the impact of heat: is it that your reservoir temperature is around 100 – 120°C, in order for your water viscosity to be only 0.5 cP? If so, what is the viscosity of your dead oil at that temperature? If you were to run the test at your reservoir temperature, how close is your viscosity ratio?
Dr. Jonathan Bryan
Marko Asks PERM:
Hi,
Thank you all for your interest. I was waiting for the viscosity data so I can replay to you.
But also maybe consider the impact of heat: is it that your reservoir temperature is around 100 – 120°C, in order for your water viscosity to be only 0.5 cP? If so, what is the viscosity of your dead oil at that temperature? If you were to run the test at your reservoir temperature, how close is your viscosity ratio?
Reservoir temperature is about 55 °C. Water salinity is about 10 g NaCl per liter which gives viscosity of about 0.5 cP on 55 °C. Dead oil viscosity at reservoir temperature is about 16 cP. So if I could run the test at reservoir temperature I would get viscosity ratio of around 32 (16/0.5=32), which is double in compare to the real reservoir viscosity ratio which is 16 (8/0.5=16).
That’s why I would like to use mineral oil and synthetic water with viscosity ratio of 16 when measuring on room temperature, thus keeping the same reservoir viscosity ratio.
Many thanks to Dr. Jon Bryan and best regards,
Best regards,
Marko
Dr. Jonathan Bryan from PERM Answers:
Hello,
Yes, this seems like a good approach in terms of the viscosity. But unfortunately, there is one more piece of the puzzle. The one last thing to think about is the wettability of the rock. If you work with a mineral oil system I assume this means that you will clean your cores of their native state fluids, then flood with water and then oil. In general, mineral oil will give you a strongly water wet rock; there is likely nothing in the oil itself that will alter wettability. So if you know that your reservoir is already strongly water wet, then you are okay working with a model oil. But if you suspect that there are some oil/rock interactions that would affect the wettability of your reservoir, then you are better off working with your actual reservoir oil and brine, and playing with temperatures.
*NOTE: This assumes that you are working on a specific reservoir, which is what I gleaned from your comments. If your goal is to look at the effect of adverse mobility ratio alone just in a general sense, then you are okay working with the model oil. But if your goal is to measure oil/water relative permeability specifically for your actual reservoir, then you may be better off working with the real fluids.
Dr. Jonathan Bryan
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