Saturday, November 20, 2021

Phase Separation & Implications in HC Migration

Here are two videos of CCE (constant composition expansion) PVT test videos kindly provided to us by Murray Macleod at Core Labs Perth. These tests are used by engineers to determine bubble or dew point pressure (pressure at which the single reservoir fluid becomes two phase). In this blog I would like to talk about the implication of this in HC migration process. I hope this helps those geoscientists not so familiar with PVT/phase behavior. I wish I had learnt this earlier in my career as a petroleum geologist. 

In the CCE tool, the rotating cylinder moves away to expand the volume of the chamber thus lowering the pressure. The first video shows what happens to a single phase volatile oil when pressure is decreased from 8000 to about 1000 psi. At about 3300 psi (which in a basin would be at about 2200 meters depth), vapor (gas) bubble begins to form (hence the term bubble point pressure). 


As pressure is further reduced,  more and more gas comes out of the solution and takes up the upper part of the chamber and the volume of the liquid decreases significantly (by a factor of more than 2 in this case). What is not obvious (and important for exploration) is that along with that the gas oil ratio (GOR) in the liquid also decreases. 

The following figure shows the path of the process in a geological setting. Following the 3 green circles from deep to shallow, the starting volatile oil (deepest green circle) has a GOR of about 2300 scf/bbl. During upward migration, phase separation starts when it reaches about 2200 meters. As the oil continues to migrate to shallower depth, it loses more and more gas. At the shallow depth, the GOR becomes 300 scf/bbl (a black oil). 

The lost gas may get trapped in small traps along the way, so we end up with an low GOR oil accumulation. Or if enough of the gas makes to the final trap, we may have a gas cap. If the trap is not able to support the column of oil and gas to spill point, it may leak the gas and retain only the low GOR oil. Or if the seal is very good but the trap is small, all of the oil may spill, and we end up with a gas accumulation. 

Again, let me be clear, although the source rock may have supplied a high GOR oil, the final trap may be a low GOR oil accumulation, or a gas accumulation, or an oil accumulation with gas cap. It is determined by the seal and the reservoir pressure!

A similar process applies to gas condensate fluid. Below is a CCE video for gas condensate. As the pressure decreases to dew point, a liquid phase forms at the bottom. The liquid volume increases as pressure decreases and more liquid comes out solution from the vapor phase. The GOR of the vapor increases (CGR decreases). Like the oil case, you may deduct what can happen at the final trap following the red circles in the figure above. Depending on if it leaks or spills, the trap may end up with a higher GOR gas, or a low GOR oil, or both. Check out the AAPG paper by John Sales (1997).    


If the starting fluid has a GOR between 3000 and 4000 scf/bbl, whether it is called oil or gas depends on what engineers find in the CCE test. If bubbles form at the top, it is called an oil, and if liquid forms at the bottom, it is called a gas condensate. This is how engineers decide if a field is called oil field or a gas condensate field. Note that even at 4000 scf/bbl, there is still more what geochemists call oil (C6+) in the fluid than gas (C1-5) in weight.   

Please let me know what you think by commenting, thanks!

Zhiyong He,
ZetaWare, Inc. 

11 comments:

  1. Zhiyong, in your experience? How often work together PVT experts and geochemist in basin modeling into companies?

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  2. Hi Mario, unfortunately, not a lot. I am afraid most but not all geochemists and modelers are not very knowledgeable about PVT and this is the reason I am posting this. There is some improvements in recent years because of the discussion on the unconventional side.

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  3. I think this is a great way to illustrate the effects of PVT on the quality of trapped fluids to geochemist/geologists/modellers not familiar with PVT.
    Great Job!

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  4. Very interesting Zhiyong. I am wondering what happens during the uplift of unconventional systems where gases and liquids can not segregate easily due to the ultra low permeability.

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    1. Hi Tristan, that is a great question. Actually we have talked about this in the 2017 paper https://www.searchanddiscovery.com/documents/2017/10968he/ndx_he.pdf Although the permeability is low, but given geological time, the phases are still separated resulting high GOR areas updip of low GOR (Delaware basin example). To us the Bone Springs reservoirs in western part of the Delaware basin is a giant gas cap. Note that if a gas cap can form in conventional reservoirs during production in one year for a 100 mD reservoir, it can happen in 1 million years for a 100 nD reservoir, and the Bone Springs is certainly much better than 100 nD.

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    2. Thanks for your comment, Zhiyong. What we observe in the Montney are mappable secondary gas migration fairways likely controlled by facies heterogeneity as well as structural lineaments. They may partly result from phase separation during uplift, but not always as they are also observed at pressures likely above the saturation pressure of in-situ fluids (> 35-40 Mpa). In other areas, we also see evidence of thermal disequilibrium between gas and oil, suggesting more diffuse migration of gas through the oil window (with possibly evaporative fractionation). These observations and the increasing overpressure with depth (lateral pressure disequilibrium) suggest to me that up-dip migration and phase segregation are still on-going processes, even though the uplift of the basin started about 80 My ago… which I find puzzling!

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    3. Gas can still migrate up dip and displace oil without phase separation. And it does not necessarily happen uniformly, it may occur in the direction of structural or stratigraphic focusing, seeking the direction and zones of least resistance (largest pore throats) to invade (I don't use the word "most permeable" - as I believe rates are too low for viscosity to matter - see my recent most on rates). The cause for continued migration include expansion of volume due to pressure decrease - especially high GOR fluids, and structure movement, so it does not have to have phase separation. The thrusting (duplication and folding) in a foreland basin increases burial (and heating) even at the same time of uplifting and erosion.

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  5. Hi Tristan, Yes migration will always happen and controlled by strategraphy, facies and structure. Composition fractionation can happen in organic rich rocks due to selective adsorption and once reaching ~6000 psi or less depending on GOR, phase related fractionation takes over.

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  6. Erosion is going on today and that means pressure is getting lower, which leads not only phase separation but but also migration due to the resulting volume expansion. As we are reducing wetting phase (Pw) pressure by erosion, it will increase capillary pressure (Phc-Pw), which will in turn try to reduce non-wetting phase saturation (imbibition) causing migration as well. Areas of imbibition will be less productive. You may find this concept from talks by Keith Shanely and Rich Gibson.

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