Capillary pressure

[@numan_tahmiscioglu]

Holding a BSc in petroleum engineering and being soon to be a MSc reservoir engineer, no body has ever explained this to me, this clear. My sincere regards

[@muhammadnabiev6000]

Your lectures are really useful and they’re easy to understand, Thanks a lot professor!

[@RingMalual-r4d]

Thank you so much, I struggled to understand this topic, but you made it simple.

[@swagsarang7381]

Hi Martin, thank you for this lecture. Appreciate it :)

[@insaf_]

Excellent explanation. Thank you

[@villaraskar1837]

dast xosh

[@RedStaggGaming]

Thanks for the interesting videos - really good to brush up again on my RE skills. I have a question... In an oil reservoir with an overlaying gas cap, when we assume that the gas cap zone started with water, migrated oil, then gas overlays either by secondary migration or evolution from the oil. Does the wetting fluid still remain as water in the gas cap zone? and if so, does the gas cap have oil trapped down to residual oil saturation as well? What would be the appropriate rel perms to use here, as we typically use two phase rel perm curves, gas-oil and oil-water. Cheers.

[@BoffyBlunt]

This is an interesting comment. Yes, in this case the gas cap could become oil-wet and for waterflooding an appropriate relative permeability may need to be used, as the water could be non-wetting to gas. We can still assume though that gas is non-wetting to oil. Over geological time, with phase exchange between gas and oil, and oil layer flow, we would not expect to see any significant residual oil saturation in the gas column though.

[@RedStaggGaming]

@@BoffyBlunt Thanks for the response! It's interesting, because I was under the assumption that if the rock has had oil saturation present (prior to gas migration) then once displaced with gas, the rock cannot go below residual oil saturation. The background behind why I ask this, I have seen cores from a pure gas producing zone completely stained with oil and it posed the question of whether early gas production instead of late field blowdown would have an impact on oil reserves, as in my head this oil saturation present in the gas cap zone cannot physically be less than the residual oil saturation and therefore trapping is unlikely to occur, and negating the effects of uneven displacement, early gas cap production and hence migration of the OWC upwards would not have an impact on ultimate oil recovery. As for modelling approaches, I have seen in an old history matched model that early GC blowdown shows a reduction in oil recovery, but I am fully aware that the initialization of the model is such that there is no oil present in the gas cap, so it's not necessarily reflective of what we see in reality from cores and hence in that case trapping would occur in the model (but perhaps not in reality?) Is there something I am missing?

[@BoffyBlunt]

@@RedStaggGaming The residual oil saturation in the presence of gas is lower than for water flooding and may be very low indeed, so I would suggest that there are only small quantities of oil in the original gas column at most. The case you mention could be where the gas cap has moved rapidly into the original oil zone and that's why you see a lot of oil staining.

[@RedStaggGaming]

​@@BoffyBlunt Interesting, thanks again for the response. In this case, in the original cas column, this would still remain then a water wet rock primarily, with residual and immobile oil (and water) saturations (smaller than O/W residual oil saturations, due to high gas saturations), and mobile high gas saturation. It's essentially 3 phase, but due to the mobility of gas being largely favoured, the other two phases do not move and can essentially be viewed as a reduction in permeability to gas. Is this correct? It's interesting, because initialization of models typically dont have any oil saturation whatsoever in the gas cap, meaning the migration of the contact upwards with gas cap production will over estimate the losses due to trapping. Is this correct?

[@BoffyBlunt]

@@RedStaggGaming Yes this is correct although after being in contact with oil the rock may be oil-wet.

[@foxhound-0]

before i continue i have seen 100 videos of this subject and non of them gave me the feelings that i have understood like this Magnificent and stunning lecture performed by this legend Dr.Blunt. Respect Sir for you and and subscribed all the best dear

[@amanraizada514]

Prof. Martin, Excellent video on Pc! What is the qualitative difference between microscopic and macroscopic Pc? Do we average microscopic Pc values over a large number of pores to find macroscopic Pc?

[@BoffyBlunt]

Yes, this is correct. At the microscale capillary pressure is defined by the curvature of a fluid/fluid meniscus. At the large-scale the capillary pressure is the average of this curvature for continuous phases, assuming the limit of slow, steady-state flow.

[@amanraizada514]

@@BoffyBlunt Thank you, Professor.

[@jahongirxayrullaev108]

Thank you!

[@ahmadragab1611]

Thank you Could you help me to solve some issues regarding this issue?

[@chrisl.2554]

This legend is using paint

[@shyamtalluri8573]

Professor a question is it necessary to include gas water cap pressure curve in Co2 injection simulation model into aquifer. Does it have a big impact on result or can we avoid including cap curve. Thanks

[@BoffyBlunt]

In most cases the explicit impact of capillary pressure in field-scale simulation is small. You can estimate this yourself by comparing typical capillary pressures with the pressure drop between wells, or between the injection well and the far-field. It is important if you wish to capture imbibition processes in thin layers, for instance, or to capture accurately an initial distribution of fluid in capillary/gravity equilibrium.

[@shyamtalluri8573]

@@BoffyBlunt professor I did a small sector model and found that if I include cap pressure I get more residual trapping and dissolution trapping. For no cap pressure case more CO2 is free state in structure. Does this make sense? Sorry to ask too many questions

[@BoffyBlunt]

@@shyamtalluri8573 This does make sense, but is often a small effect. This shows you need to include capillary pressure in this case. Capillary pressure tends to smear out the CO2 profile, allowing more capillary and dissolution trapping. Make sure that you correctly represent capillary trapping in the relative permeability functions though.

[@shyamtalluri8573]

@@BoffyBlunt it is a small difference in dissolution trapping but a big difference in residual trapping. Like wise big difference in free gas between cases with and without cap pressure. But if summed all difference is small for two cases

[@shyamtalluri8573]

@@BoffyBlunt yes included cap pressure curve in gas water rel perm curve need to use a key word GSF in eclipse. Thanks

[@shyamtalluri8573]

We did a steady state experiment but Sw is not reduced to.Swir. how can we use this relative perm data for water gas? Can it be used if swir is not determined? Thanks professor

[@BoffyBlunt]

You can use the results you have for the saturation range studied. To extrapolate the water relative permeability to zero at Swir, you do need to estimate this saturation from other experiments or analogues.

[@ahmedadil3352]

Dear Martin Can you explain why cos is close to 1 as you mentioned in the time 6:24 of this vedio.

[@BoffyBlunt]

Yes because in drainage the porous medium is normally strongly water-wet with a contact angle close to zero.

[@ahmedadil3352]

Thank you @@BoffyBlunt for the prompt reply. I really appreciate it. Can you, please, refer me to some literature so that I can dig deeper.

[@ahmadragab1611]

Explain how the equation for capillary pressure in straight capillaries is derived from the Plateau equation.

[@BoffyBlunt]

Can you be more explicit please? What is the Plateau equation? Do you really mean Young-Laplace? For straight capillaries, do you mean two parallel plates?

[@هيثمعباس-خ4ث]

Hello... why at constant capillary pressure the saturation of imbibition process is lower than the saturation of the drainage process

[@BoffyBlunt]

For three reasons. 1. The non-wetting phase can be trapped in imbibition, but is connected in primary drainage: this trapped saturation lowers the connected saturation of the wetting phase. 2. Contact angle hysteresis - for the same capillary pressure, you are filling a smaller region of the pore space at a lower wetting phase saturation. 3. Different displacement processes - again you are filling a smaller region of the pore space.

[@هيثمعباس-خ4ث]

@@BoffyBlunt Thanks 🌹

[@stalluri11]

What happens when co2 is injected?

[@BoffyBlunt]

If CO2 is injected into the pore space, then there is a capillary pressure between CO2 and water (and oil, if present). Generally, the CO2 is the non-wetting phase.

[@stalluri11]

@@BoffyBlunt thanks. Curious to ask if you have any typical rel perm and cap pressure data files to use in simulation. Thanks for your help

[@BoffyBlunt]

@@stalluri11 These are normally measured values. If you see my videos on relative permeability, typical functions for different wettabilities are presented.

[@baraajameel4173]

شكول عليج يتبارك كلساع وكمزني😂💔