There are rarely continuous connecting sandstone bodies from the source rock to the reservoir and petroleum must therefore migrate through shales. Fluid flow through shales may occur in different ways:
- Matrix-controlled (intergranular flow).
- Flow in fractures produced by hydro-fracturing due to overpressure (mostly microfractures).
- Flow in tectonically induced macrofractures.
In the case of matrix-controlled flow the capillary entry pressure and the permeability are a function of the pore size distribution and diagenetic alterations. In shales the typical pore sizes may be a few 100 Å or less. In the Gulf Coast the pore diameter may be less than 25 Å at 3–4 km depth and less than 10 Å at 4–5 km burial. The size of the largest pores and their connections will however determine the permeability. It the largest connecting pore size is below 50 Å this is approaching the size of the asphaltenes in crude oil. A sieving effect should therefore be observed relative to the size of the organic molecules if the pore throats are below this value. Migration of oil through low permeability shales probably only happens along fractures and not through the shale matrix. Fractures in shales may be formed tectonically during uplift and extension when the shales are brittle. Relatively large fractures may occur because the horizontal stresses trying to close the fractures are generally small. This is a common cause of oil and gas leakage from reservoirs. However, nearly all on shore reservoir sand many offshore reservoirs have experienced some uplift from their maximum burial depth and in a rock mechanical sense are therefore over consolidated and will tend to be brittle. During basin subsidence, tectonic shear produces fractures during ductile deformation and these fractures are then no more permeable than the matrix. Oilfields are often highly over pressured, with many of them leaking petroleum at the top of the structure which is often close to the fracture pressure. This means that it is the horizontal stress and the tensional strength of the rocks that control the pressure. When the pressure is close to fracture pressure it implies that faults are no longer the conduits for fluid flow because the rock matrix would then fracture and let the oil through. If faults were a zone of weakness the fluid pressure should have remained below fracture pressure. In the case of traps formed by rotated fault blocks the top of the structure will usually coincide with a fault. Even if seismic evidence indicates gas leakage from the top of the reservoir, this does not necessarily mean that the leakage is along the fault, because fracturing of the cap rock will occur in approximately the same position. We must distinguish clearly between migration of oil along a fault plane and across it. If there is sand on both sides of the fault plane it is difficult to predict if the fault will be a barrier for oil migration. Sealing faults are often critical for the formation of traps in rotated fault blocks. Clay smears from adjacent shales can serve as a barrier at shallow depth, while at greater depth intensive quartz cementation may reduce the permeability and the capillary entry pressure for oil. In subsiding basins, fault planes are at shallow to moderate burial depth and are subjected to shear deformation which produces clay smearing, so that the permeability along the fault is normally lower than through the rock matrix. After tectonic displacement, faults may also be subject to cementation. During tectonic uplift, however, faults may be extensional and much more permeable. Migration due to hydrofracturing of shales. If the fluid pressure exceeds the fracture pressure the rock will hydrofracture. The pressure required to fracture the rock can be measured in a well by using a leak-off test. However, the LOT creates micro-fractures which develop at a lower pressure than that required to form proper fracturing. These micro-fractures should theoretically develop when the pressure exceeds the sum of the least horizontal stress and the tensional strength of the rock. Since the pressure required for large scale fractures to form (fracture pressure) is higher than the LOT test value, the tensional strength which allows micro-fractures to form is lower than when forming proper hydrofracturing. In the case of micro-fractures (LOT tests) these probably deform the rock in a different way, so that the rock can heal once the pressure is released. Fractures developed by hydrofracturing during leakage of oil are likely to be vertical because they develop parallel to the direction of maximum stress which is normally vertical in subsiding basins with little external tectonic stress. As a fracture opens, the permeability along it is increased. This reduces the pressure gradient along the fault plane to less than the fracture gradient. The top of the fracture may therefore be above fracture pressure, while the lowest part is below fracture pressure and subject to effective stress trying to close it. The fractures produced by hydrofracturing must therefore propagate upwards and are of limited vertical extent. They develop first in the least permeable parts of the shale (cap rock) which may only contain water because of low capillary entry pressure. The pressure in these very small water-saturated pores should not be influenced by the pressure in the petroleum phase in the sandstones. The excess pressure in the petroleum phase compared to the water pressure, is held by the capillary forces and does not influence the pressure causing onset of hydrofracturing. However once the first fracturing has occurred the petroleum will be the continuous phase along the fracture, and it is the pressure in the hydrocarbon phase which causes leakage when the horizontal stress is exceeded. In the laboratory, water has been shown to flow though a cap rock while oil has been retained by the capillary pressures. If we consider migration in two dimensions it is clear that it is not only the source rock that will fracture. All the overlying shales that could serve as potential cap rocks could reach fracture pressure and leak petroleum if there are no lateral drainage paths. This is because the fracture pressure gradient is steeper than the fluid pressure gradient. Accumulation of petroleum in a trap capped by shale which does not fracture, requires that the pressure be reduced by lateral flow of water to maintain pressure below fracture pressure.
