If a trap has a large enough closure height, the capillary top seal becomes the limit of the oil column height trapped when available charge is sufficient. The maximum column height, Ho, is given by the capillary equation:

where ρw and ρo are densities of water and oil respectively. γo is the interfacial tension between water and oil, θ the contact angle, g the acceleration of gravity and r the pore throat radius of the seal. In the case of a gas only column, one can simply substitute the subscript o with g, replacing the density and interfacial tension for gas. Since subsurface gas density is typically 1/3 to 1/2 of oil density, and γg is 1.5 to 2 times γo, the maximum gas column is about 20% to 30% smaller than for an oil column.

where ρw and ρo are densities of water and oil respectively. γo is the interfacial tension between water and oil, θ the contact angle, g the acceleration of gravity and r the pore throat radius of the seal. In the case of a gas only column, one can simply substitute the subscript o with g, replacing the density and interfacial tension for gas. Since subsurface gas density is typically 1/3 to 1/2 of oil density, and γg is 1.5 to 2 times γo, the maximum gas column is about 20% to 30% smaller than for an oil column.

Under dual phase (gas cap over an oil leg) conditions, because γg is higher than γo, the capillary force against gas at the crest is stronger than that against the oil column at the GOC for the same pore throat radius at base of the seal. This leads to a combined maximum column larger than the maximum oil only column, as the gas cap cannot be completely leaked off.

At equilibrium, the capillary force, Pcg, at the crest is balanced by the buoyancy of the combined column:

Pcg = 2· γg · cos(θ)/r = Hg· g· (ρw-ρg) + Ho· g· (ρw-ρo)

while at the GOC, the capillary force, Pco, is balanced by the oil column:

Pco = 2· γo · cos(θ)/r = Ho· g· (ρw-ρo)

Combine the two equations and canceling out r and cos(θ), we have:

Pcg = 2· γg · cos(θ)/r = Hg· g· (ρw-ρg) + Ho· g· (ρw-ρo)

Pco = 2· γo · cos(θ)/r = Ho· g· (ρw-ρo)

Combine the two equations and canceling out r and cos(θ), we have:

Under typical reservoir conditions, this results in a gas cap that is about 1/6 to 1/5 of the oil column.

The implication of this is that small gas caps may occur more frequently in large structures than we expect otherwise, as long as it is a dual phase system. This can also explain stacked pays that have gas caps at more than just the top reservoir. The Kikeh field in deep water Malaysia may be such a case. The "gas chimney" above the field, as well as the multiple pays indicate top seal control of the columns. Several of the stacked reservoirs have a small gas cap.

Even if the seal can support an oil column larger than the trap closure, gas cap over oil leg can still be the case as long as it cannot also support a full gas column, as described by my earlier post.

Very nice expansion/correction of the classic paper by Sales (1993) about trap capacity and sealing. It seems to me there are a number of implications to what Zhiyong has posted here, and some predictive power. Maybe the most typical scenario where these concepts come into play would be a case where you have early oil charge that fills a trap to leak. The accumulation is dynamic after that, with any new oil migrating in causing an equal amount of leakage. Eventually though, you start getting two-phase behavior--probably due to the GOR of the migrating fluid increasing, but possibly due to a reduction in pressure. What this blog tells us, that might not be intuitive (it wasn't to me), is that a gas cap will now form, without causing any leakage of the previously emplaced oil leg. And this is due to the difference in interfacial tension of oil-water and gas-water. Similarly, if you had an early gas accumulation (perhaps microbial) and oil then migrated in, only some of the gas would leak off--you would be left with this cap 15-20% the height of the oil leg.

ReplyDeleteAt the extremely high charge rate of 500 (80 m3) barrels/year (5 bln barrels over 10 million years), the flow rate over a 100 m x 100 m area to match the charge rate is about 0.08 m/year at 10% porosity. It seems even for us geologists it is hard to appreciate the enormous difference between geological time scale and production time scale. Most cases the charge rate would be orders of magnitudes smaller.

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