Various suggested primary and secondary petroleum migration mechanisms are reviewed, with emphasis on hydrocarbon solubilities in water.

Primary migration of crude oil in aqueous solution is shown to be not possible because of (1) the very low solubilities of high-molecular-weight hydrocarbons, compared with low-molecular-weight hydrocarbons; and (2) the markedly higher solubilities (185 to 650 times) of aromatic hydrocarbons with up to 20 carbon atoms in the molecule, compared with the corresponding carbon number alkanes. Thus, hydrocarbons in water solution in equilibrium with crude oils consist typically of more than 60% benzene plus toluene in the C₆+ fraction. However, the concentrations of benzene and toluene in crude oils are typically 1% or less. The low-molecular-weight alkanes (C₁-C₅) have high solubilities in water, and natural gas may migrate dissolved in water.

Migration of oil solubilized in surfactant micelles is not feasible, because a large amount of surfactant would be required to attain a critical micelle concentration (CMC). The size of micelles, if formed, would be too large to pass the small pore throat constrictions in source rocks.

Migration by oil droplet expulsion also is not feasible, because of the difficulty of overcoming the high interfacial forces of small drops in small pores. Even if interfacial tensions between oil and water could be lowered sufficiently for oil flow, the source rock would be required to convert at least 7.5% organic matter by volume in order to attain 30% oil saturation required for separate phase flow. Attaining higher oil saturations required for "squeezing" oil from pores would require even higher organic matter concentrations. If oil expulsion did occur, the residual oil saturation would be at least 20% in all source rocks after oil migration. Such concentrations have not been universally observed.

All processes whereby generated petroleum enters into or moves with water do not seem possible, because of chemical and physical constraints.

Petroleum, in all likelihood, is generated in and flows from source rock in a three-dimensional organic matter (kerogen) network. Scanning electron micrographs clearly show a three-dimensional kerogen network after minerals have been removed by acid treatments. Petroleum flowing

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in this hydrophobic network is not subject to interfacial forces until bubbles of gas or droplets of oil enter the much larger water-filled pores in the reservoir rock. Oil will flow under the same forces of compaction or pressure developed by gas formation, or by volume expansion associated with petroleum generation.

Oil and water flow are independent processes; that is, water flow is not required for primary or secondary petroleum migration. The oil saturation in the kerogen for oil flow to occur is indicated to be from 2 to 10%, based upon hydrocarbon analysis for organic matter in a large number of suspected source rocks. The lower limit of 0.5 to 1% organic matter content for potential source rocks may be due, not to lack of generation potential, but to lack of a three-dimensional kerogen network in rocks containing less organic matter.

Secondary migration of separate-phase oil and gas should occur by buoyancy, when their saturations attain 20 to 30% along the upper or lower surface of the reservoir rock. Petroleum entering at the lower surface would cross the rock when the buoyancy head became sufficient for separate-phase flow. This cross-formational flow would occur at occasional intervals. Migration would occur along the upper few centimeters in the reservoir rock from source to trap, thereby providing an efficient migration mechanism. The volume of reservoir rock that attains oil or gas saturation during secondary migration should be small. Water flow is not required.

In contrast, secondary migration of hydrocarbons in solution (gas, oil, and micelles) would be very inefficient and require large volumes of water. Secondary migration by solution would require all pores in a reservoir rock to attain 20 to 30% gas or oil saturation before separate-phase flow could occur. Smaller pores may attain higher gas or oil saturations. If separate-phase flow were not attained, petroleum would be locked in the pores and would not be available to form gas or oil reservoirs in trap positions.

At 4572 m (15,000 ft) and a temperature of 160°C, a flow of about 90 pore volumes (PV) of gas-saturated water would be required to attain 30% gas saturation. At 1524 m (5000 ft) and 60°C, 200 PV flow would be required. Moving oil in solution would require much more water: 15,000 PV at 4572 m, and 200,000 PV at 1524 m. Limited solubility data suggest that even at 7929 m (26,000 ft) and 270°C, about 4500 PV of hydrocarbon-saturated water would be required to attain an oil saturation of 30%. Cores taken from any portion of the reservoir rock along the secondary migration pathway should show this residual gas or oil saturation. Recovered water should always contain the equilibrium concentrations of each individual hydrocarbon based upon its pure solubility in water and its mol fraction concentration in the separate gas or oil phase present in the rock pores. This has not been generally observed.

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In actuality, water flow probably disperses water-soluble constituents instead of concentrating them in reservoir traps.