by Zhiyong He, ZetaWare, Inc.
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:
- North Sea, Middle Jurassic and older reservoirs below the KCF
- North Africa, the Ordovician sandstone reservoirs in Ghadames, Illizi and Murzuq basins, below the Silurian hot shale source cock
- Bohai, Oil fields in Paleozoic basement, “Buried Hills”, karst tomography, between and under the Tertiary grabens that contain the Oligocene source rock.
- Similarly, the Bach Ho (White Tiger) oilfield in fractured granite basement underlying Oligocene source rocks in Vietnam.
- Woodbine (giant East Texas field) underlying the Eagle Ford source rock.
- Muddy/Lakota reservoirs underlying the Mowry shale in Powder River basin.
- Cambrian and Ordovician oil and gas fields charged from the Utica source rock above in Ohio and Indiana, of the Appalachian basin.
- Hunton reservoirs charged from the Woodford above in the Anadarko basin.
- Three forks reservoirs and the Bakken source rock above in Williston basin.
- The Norphlet plays in onshore Mississippi, Alabama and more recently the Eastern GoM deep water where the Smackover is the source and the seal.
- The Tuscaloosa sands below the Tuscaloosa Marine Shale (TMS)
- 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
|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.|
- 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.
- Saturation at the boundary stays low as it is easier to expel due to the sharp gradient in Pc.
- 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)
- 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.
|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.|
- 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.
- 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.