Changes

By Mike Shepherd, AAPG Memoir 91, Oil Field Petroleum Geology

By Mike Shepherd, [http://store.aapg.org/detail.aspx?id=788 AAPG Memoir 91, Oil Field Petroleum Geology]

When hydrocarbons migrate into a trap, the buoyancy force exerted by the lighter oil (or gas) will push the water that was previously in the pore space sideways and downward. However, not all of the water is displaced; some of it will be held by capillary forces within the pores. Narrower capillaries, pores with smaller pore throats, hold onto water the strongest.

When hydrocarbons migrate into a trap, the buoyancy force exerted by the lighter oil (or gas) will push the water that was previously in the pore space sideways and downward. However, not all of the water is displaced; some of it will be held by capillary forces within the pores. Narrower capillaries, pores with smaller pore throats, hold onto water the strongest.

Mercury will not enter the rock immediately. The pressure required to do this will depend on the radius of the pore throats, the contact angle, and the mercury-air interfacial tension. The pressure at which the mercury effectively enters the pore network is termed the displacement or entry pressure (Vavra et al., 1992). Lower entry pressures are found in the better quality reservoir rocks, that is, those with larger pore throat diameters. A cap rock with tiny capillaries, shale for instance, has a very high displacement pressure. The displacement pressure for a cap rock can be so high that the tightly bound water in the pore space of the shale will prevent the oil from entering and the oil remains trapped in the underlying reservoir rock (Berg, 1975; Schowalter, 1979).

Mercury will not enter the rock immediately. The pressure required to do this will depend on the radius of the pore throats, the contact angle, and the mercury-air interfacial tension. The pressure at which the mercury effectively enters the pore network is termed the displacement or entry pressure (Vavra et al., 1992). Lower entry pressures are found in the better quality reservoir rocks, that is, those with larger pore throat diameters. A cap rock with tiny capillaries, shale for instance, has a very high displacement pressure. The displacement pressure for a cap rock can be so high that the tightly bound water in the pore space of the shale will prevent the oil from entering and the oil remains trapped in the underlying reservoir rock (Berg, 1975; Schowalter, 1979).

With increasing injection pressure, more and more mercury is forced into the rock. The shape of the curves on a capillary pressure plot reflects the grain sorting and the connection of pores and pore throats. The longer the plateau shown by the capillary curve, the better the reservoir quality. Poorly sorted, fine-grained sediment with narrow pore throats will retain water to higher pressures than coarser grained, better sorted sediments. A homogenous reservoir rock can be represented by a single capillary pressure curve. By contrast, a heterogenous reservoir will have a family of rock types, each with its own capillary pressure curve (Figure 27).

 

With increasing injection pressure, more and more mercury is forced into the rock. The shape of the curves on a capillary pressure plot reflects the grain sorting and the connection of pores and pore throats. The longer the plateau shown by the capillary curve, the better the reservoir quality. Poorly sorted, fine-grained sediment with narrow pore throats will retain water to higher pressures than coarser grained, better sorted sediments. A homogenous reservoir rock can be represented by a single capillary pressure curve. By contrast, a heterogenous reservoir will have a family of rock types, each with its own capillary pressure curve ([[:file:Mem91BuoyanceForcesFig27.jpg|Figure 2]]).

Petrophysicists will use capillary pressure curves as the basis for deriving a water saturation versus height relationship for a reservoir (Vavra et al., 1992).

Petrophysicists will use capillary pressure curves as the basis for deriving a water saturation versus height relationship for a reservoir (Vavra et al., 1992).