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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.

* theta is the contact angle between the wetting fluid and the solid surface, and  

* theta is the contact angle between the wetting fluid and the solid surface, and  

* r is the capillary (pore throat) radius (Vavra et al., 1992{{citation needed}}).

* r is the capillary (pore throat) radius (Vavra et al., 1992{{citation needed}}).

The volume of water remaining at a given height in a reservoir is a function of the balance of capillary forces pulling the water up from the hydrocarbon-water interface and the force of gravity acting together with the density contrast between the reservoir fluids, acting to pull the water down (Arps, 1964{{citation needed}}). Thus, a given part of the pore space within the hydrocarbon leg can contain both hydrocarbons and water. The fraction (percentage) of water to total fluid volume is termed the water saturation.

The volume of water remaining at a given height in a reservoir is a function of the balance of capillary forces pulling the water up from the hydrocarbon-water interface and the force of gravity acting together with the density contrast between the reservoir fluids, acting to pull the water down (Arps, 1964{{citation needed}}). Thus, a given part of the pore space within the hydrocarbon leg can contain both hydrocarbons and water. The fraction (percentage) of water to total fluid volume is termed the water saturation.

For an oil field, the capillary-bound water comprises a continuous column of water within the oil leg, which will have a hydrostatic pressure gradient controlled by the water density. The oil is located in the remaining pore space as a continuous phase and will have a pressure gradient controlled by the (lower) oil density ([[:file:Mem91BuoyancyForcesFig26.jpg|Figure 1]]). Although oil and water can coexist in the same localized volume of rock, the pressures acting on the two fluids are different. The difference in pressure between the oil and water phases increases with height above the free-water level. The free-water level is the level at which the water-hydrocarbon interface would theoretically stand in a large open hole drilled through the oil column (Schowalter, 1979{{citation needed}}). In this situation, only gravity and buoyancy forces control the fluid distribution in the borehole.

For an oil field, the capillary-bound water comprises a continuous column of water within the oil leg, which will have a hydrostatic pressure gradient controlled by the water density. The oil is located in the remaining pore space as a continuous phase and will have a pressure gradient controlled by the (lower) oil density ([[:file:Mem91BuoyancyForcesFig26.jpg|Figure 1]]). Although oil and water can coexist in the same localized volume of rock, the pressures acting on the two fluids are different. The difference in pressure between the oil and water phases increases with height above the free-water level. The free-water level is the level at which the water-hydrocarbon interface would theoretically stand in a large open hole drilled through the oil column (Schowalter, 1979{{citation needed}}). In this situation, only gravity and buoyancy forces control the fluid distribution in the borehole.

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{{citation needed}}). 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{{citation needed}}; Schowalter, 1979{{citation needed}}).

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{{citation needed}}). 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{{citation needed}}; Schowalter, 1979{{citation needed}}).

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]]).

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]]).