Composition Fractionation During Petroleum Migration

By Zhiyong He, ZetaWare, Inc.

One of the goals of petroleum system modeling and analysis is to predict fluid composition and properties (GOR, API gravity etc.). However, most of the work in the past has been focused on the generation process, with compositional kinetics, etc. Below I will try to show that the petroleum under goes significant changes in composition and properties along the migration pathways due a number of secondary processes not well understood yet.  Most people are familiar with the Gussow (1954) migration model in the figure below. The trap closest to the kitchen would receive the latest, and most mature and therefore lighter fluid, which displaces less mature fluid to traps up dip. 

Fig. 1. Differential entrapment of petroleum along migration path (Gussow, 1954). Late forming gas displaces oil to up dip traps. 

Even without forming gas caps, the later fluid tends to reach the crest of the trap because it is lighter and more buoyant. This pattern is generally true in most basins. Oils with lower gas oil ratios, and lower API gravities are found further away from the generation kitchen. Closer to the kitchen, lighter fluids, sometimes gas condensates are found. 

There are a couple of other factors not obvious from the Gussow model. When the migrating fluid reaches bubble point, a separate gas (vapor) phase starts to form, as shown in the trap in the middle. The gas in the gas cap selectively dissolves the lightest fraction of the liquid as condensate. The remaining oil in the leg retains the heavier part of the incoming fluid. The physical properties in a dual phase trap would over time equilibrate to profiles shown in the figure below. 

Fig. 2. Properties of fluid in a dual phase trap under thermodynamic equilibrium. Red and green lines are reservoir pressure of the gas phase, and oil phase respectively. The blue dashed lines show both phases are undersaturated away from the gas oil contact. GOR and API gravity both decrease with depth, in both phases. 

The dashed lines are bubble point pressure (Pb) and dew point (Pd) pressures. The oil near the oil water contact is always the least saturated with gas, lowest in GOR and heaviest in gravity, as is the the oil that spills from the trap to the next. If the trap is leaking from the crest, the next trap above will receive a gas with lowest condensate content. 

Phase separation happens due to pressure drop below saturation pressure, so it happens along the migration path as well as in traps. If it happens along the migration path, the gas would gradually "bubble" out from the migrating oil phase and either get stuck along the migration pathway as residual saturation (migration losses), because relative permeability for the minor phase is much lower or zero, or trapped in small traps below seismic resolution, along with the light ends of the oil fraction (condensate) dissolved in the lost gas.  The remaining oil will have less solution gas, and become heavier, gradually.  

Even in single phase traps, not only the late arriving lighter fluid goes to the top and displaces the heaver fluid to the flank due to gravity (charge disequilibrium). Gravity segregation and thermal equilibrium may enhance or alter the composition profiles. The figure below shows some observed GOR and API gravity profiles in single phase reservoirs in different basins. 

Fig. 3. Fluid property (API gravity and GOR) profiles in single phase reservoirs, plotted against depth below crest of the trap. Both API gravity and GOR decreases toward the oil water contact.

Significant grading occurs in near critical fluids, as show in figure (c) on the right. These profiles are controlled by complex migration and filling process and PT history and some not well understood thermodynamic processes. Therefore we do not yet have the ability to predict the composition and properties of the fluids quantitatively during the migration process. There are also other secondary processes such as mixing, methane diffusion, water washing, stripping by non-HC gases, biodegradation that can significantly alter the fluid properties. 

In the previous post below. I discussed an alternative "top down" approach to provide a probabilistic estimate of the fluid type and properties in a given prospect.   

Select references:

Gussow, W.C., 1954. Differential entrapment of oil and gas - a fundamental principle. American Association of Petroleum Geologists, Bulletin 38, 816-853

Zhiyong He, and Andrew Murray, 2020.  Migration loss, Lag and fractionation: Implications for fluid property prediction and charge risk. AAPG annual conference, Houston Texas, Sept 28-30, 2020.