Downward Migration: Observation and Mechanisms

by Zhiyong He, ZetaWare, Inc.

Observation:

I have been asked often in my training classes about downward migration. Is downward migration limited, or does it present a higher risk? What is the mechanism for large scale downward migration/charge? Is there a way to estimate the volumes for upward vs downward migration?

I want to start with observations. Many large accumulations have been discovered in reservoirs stratigraphically older than the source rock in many basins. Here are some examples that I am familiar with:

1. North Sea, Middle Jurassic and older reservoirs below the KCF 
2. North Africa, the Cambrian, Ordovician sandstone reservoirs in Ghadames, Illizi and Murzuq basins, below the Silurian hot shale source cock. The giant Hassi Messaoud field produces from Cambrian, some distance below the source rock.
3. Bohai, Oil fields in Paleozoic basement, “Buried Hills”, karst tomography, between and under the Tertiary grabens that contain the Oligocene source rock.
4. Similarly, the Bach Ho (White Tiger) oilfield in fractured granite basement underlying Oligocene source rocks in Vietnam. 
5. The biggest oil fiend in the United States lower 48 is the East Texas Field (> 10 billion barrels) that produces from the Woodbine sandstone directly below the Eagle Ford source rock. 
6. The biggest oil field in Anadarko basin is the Oklahoma City Field which produces from the Ordovician Wilcox formation, charged from the Devonian Woodford source rock above.
7. In California, the giant Midway-Sunset oil field also produces from the Temblor formation below the Monterey source rock.  
8. Muddy/Dakota reservoirs underlying the Mowry shale in Powder River basin. 
9. Cambrian and Ordovician oil and gas fields charged from the Utica source rock above in Ohio and Indiana, of the Appalachian basin. 
10. Three forks reservoirs and the Bakken source rock above in Williston basin.
11. The Norphlet plays in onshore Mississippi, Alabama and more recently the Eastern GoM deep water where the Smackover is the source and the seal.  
12. The Tuscaloosa sands below the Tuscaloosa Marine Shale (TMS)

Some other observed characteristics are:

• The source rock is often also the seal 
• Reservoirs can be separated by one ore more shales/sands from the overlying source (eg. North Sea and Williston basin). 
• In some cases, lateral juxtaposition across faults may help explain accumulations, and some are harder to explain. 

Downward Migration Mechanism

I would explain downward migration as driven by the natural capillary process. The figure on the left below shows the typical capillary curves of a reservoir and a shale (source rock). The shale has a very steep curve and pressure increases quickly with HC saturation. The center and right figures show the theoretical capillary pressure (difference between the HC phase pressure and water pressure,  Pc = Po-Pw), profiles before and during HC generation. 

Fig. 1, Capillary drive mechanism for primary migration. Pressure in the non-wetting phase HC is higher due to saturation increase cased by HC generation.

During generation, as oil saturation increases in the shale, so does capillary pressure and the oil near the sand is pushed into the sand due to capillary pressure difference: energy/potential for the non-wetting phase HC fluid is much lower in the sand than in the shale.

1. Oil saturation and therefore capillary pressure in the center of the shale is higher as it is further away from the sand. Pc can be several hundred psi even at 20% oil saturation.
2. Saturation at the boundary stays low as it is easier to expel due to the sharp gradient in Pc.
3. Buoyancy gradient for oil (~0.1 psi/ft) or gas (~0.3 psi/ft) is much smaller compared to capillary gradients ( which can easily reach several hundred psi over the half thickness of the source rock)
4. Capillary pressure is in addition to any pressure increase due to hydrocarbon generation, or compaction. And it is a higher in magnitude force than both over the source rock thickness. 

Additional Controls

The above assumes a homogeneous layer of source rock. In nature, the source rock may vary vertically in pore sizes. If the source formation is deposited as a fining upwards sequence, the capillary pressure is higher at the top with smaller pores. This will cause more volumes to migration downward. 

If the source rock is overlain by a tighter formation, and underlain by a good reservoir, nearly all the volume will migrate downward. This may be the case with the biggest oil field in the lower 48 of US, the East Texas field. The Woodbine sandstone reservoir sits directly below the Eagle Ford source. The tight Austin chalk is above the Eagle Ford. 

If the source interval has inter-bedded silty zones, hydrocarbon saturation in the more porous zones will be higher in order for the Pc to exceed the sealing capacity of the tighter zones. This essentially creates the favorable condition for a unconventional play.  Check out this post for more on this. 

Overpressure and the "centroid" effects of carrier beds may further enhance downward migration. The figure below is after the North Sea, and the Norphlet examples. The water pressure in the source rock is expected to follow the regional compaction driven over pressure. The sand below has limited vertical extent, which causes the classic centroid pressure effect. The pressure in the sand will follow the line parallel to the hydrostatic pressure, but higher. At the deeper end, usually the HC kitchen, the shale is more over pressured than the sand below, and the resulting hydrodynamic force will help downward migration.  

Fig. 2, Effects of over pressure on primary migration. Downdip area of the carrier beds are under pressured relative to the source rock. At the crest, the opposite is true, which may limit column heights of accumulations.

Accumulations usually occur at the shallow end, and some volumes migrated below the source rock may leak up to younger reservoirs. Note that Both capillary force and centroid pressure drive help upward expulsion as well, if the sand is above the source. 

Discussions:

Human intuition is that we want to quantify the volumes that migrate upwards vs downwards, especially as a basin modeler. The uncertainty is large. I would simply assume that roughly 50% of the volumes should migrate downwards if the reservoir is directly below the source rock, plus/minus the uncertainty, more if there is a tight formation above the source rock. If the reservoir is further down stratigraphy, the risk goes higher, as it may need to rely on juxtaposition, or coarsening downward stratigraphy, etc. No, the modeling software cannot tell you this (whatever the vendor may claim their software can do), you have to make such arguments, or assumptions, like most things with basin modeling. 

Limited columns in Northpet traps:

• Some have observed that Norphlet play seems to have limited column heights compared to structure closure, and have suspected that it could be due to the limited efficiency perceived of downward migration.  Steve Walkinshaw observed that the Norphlet sand only has a oil column if the overlying Smackover porosity is filled, or where the Smackover is tight (http://www.visionexploration.com/norphlet.htm), implying that it may be volume limited.   
• My own interpretation, based on concepts given this presentation and my other presentations on seals/column height and charge limitation, is that these could be seal capacity limited. Where the Smackover is tight, it is simply a better seal. In my observations and estimates, where column height is less than the trap closure, it is often are often limited by the seal capacity, rather that charge volumes. We may find stacked pays with similar columns.  In some cases, we may find an empirical correlation between column heights and effective stress.  
• In general, volume can be limited if the fetch areas are small or the source rock is very weak. However, in majority of cases, trap sizes are typically much smaller than the estimated change volumes.
• We may never know the reason for sure in a particular case. So we should use any empirical rule of thumb we can find if it helps to reduce risk. Meanwhile, we should continue to look for evidence, correlations and new explanations.  

Conclusions:

• Downward migration should be very effective as large scale forces exist to drive downward migration.
• If the reservoir/carrier is directly below source rock, chance of charge should be high as evidenced by the examples of several prolific basins. 
• Lateral juxtaposition across faults may be helpful, especially for migration into reservoirs further down stratigraphy, but it is not required for sands directly below the source rock.