Changes

[[file:fluid-contacts_fig5.png|thumb|{{figure number|5}}Irregular contact caused by semipermeable barriers in a reservoir. (a) Capillary behavior of the reservoir and barriers A, B, and C. (b) Fluid contact elevations result from charging of the reservoir from the left. Each compartment of the reservoir has a different free water surface and oil-water contact. The displacement pressure of bed A causes the contact elevation difference between contacts 1 and 2. The displacement pressure of fault B results in the elevation difference between contacts 1 and 3. The displacement pressure of the mineralized fracture C results in the difference in elevation between contacts 3 and 4. The gas column is not thick enough to invade across the fault.]]

[[file:fluid-contacts_fig5.png|thumb|{{figure number|5}}Irregular contact caused by semipermeable barriers in a reservoir. (a) Capillary behavior of the reservoir and barriers A, B, and C. (b) Fluid contact elevations result from charging of the reservoir from the left. Each compartment of the reservoir has a different free water surface and oil-water contact. The displacement pressure of bed A causes the contact elevation difference between contacts 1 and 2. The displacement pressure of fault B results in the elevation difference between contacts 1 and 3. The displacement pressure of the mineralized fracture C results in the difference in elevation between contacts 3 and 4. The gas column is not thick enough to invade across the fault.]]

Reservoir rocks may have substantially different pore structures in different parts of a field. These heterogeneities may result in significant variations in hydrocarbon-water contacts, especially in low permeability reservoirs ([[:file:fluid-contacts_fig4.png|Figure 4]]). Where all reservoir facies are very porous, heterogeneity of depositional environments does not significantly affect fluid contact elevation.

Reservoir rocks may have substantially different [[Pore system shapes|pore structures]] in different parts of a field. These heterogeneities may result in significant variations in hydrocarbon-water contacts, especially in low-permeability reservoirs ([[:file:fluid-contacts_fig4.png|Figure 4]]). Where all reservoir facies are very porous, heterogeneity of [[depositional environments]] does not significantly affect fluid contact elevation.

Fluid contact elevations in different control wells can be empirically related to lithofacies at the contact. Where critical lithofacies are not penetrated at the fluid contact, the contact elevation of the lithofacies can be predicted from capillary pressure and relative permeability tests (see “Relative Permeabilities”). The greater the difference in capillary pressure and relative permeability behavior for different lithologies within a reservoir, the greater the potential for fluid contact differences caused by heterogeneity. Because surface tension between oil and gas is usually low in subsurface reservoirs,<ref name=pt06r63>Katz et al., 1957, Handbook of Natural Gas Engineering: New York, McGraw-Hill, 802 p.</ref> the effect of reservoir heterogeneity on oil-gas contacts is usually small.

Fluid contact elevations in different control wells can be empirically related to lithofacies at the contact. Where critical lithofacies are not penetrated at the fluid contact, the contact elevation of the lithofacies can be predicted from [[capillary pressure]] and [[Relative Permeabilities|relative permeability]] tests. The greater the difference in capillary pressure and relative permeability behavior for different lithologies within a reservoir, the greater the potential for fluid contact differences caused by heterogeneity. Because [http://en.wikipedia.org/wiki/Surface_tension surface tension] between oil and gas is usually low in subsurface reservoirs,<ref name=pt06r63>Katz et al., 1957, Handbook of Natural Gas Engineering: New York, McGraw-Hill, 802 p.</ref> the effect of reservoir heterogeneity on oil-gas contacts is usually small.

Fluid contacts can be extrapolated from control wells if distribution of different reservoir rock types and their capillary properties can be mapped. In many cases, the distribution of rock types within heterogeneous reservoirs is poorly characterized during initial development, so the largest uncertainty in mapping the fluid contact is the uncertainty in the distribution of the lithofacies. The position of the hydrocarbon-water contact may need to be confirmed by well penetration.

Fluid contacts can be extrapolated from control wells if distribution of different reservoir rock types and their capillary properties can be mapped. In many cases, the distribution of rock types within heterogeneous reservoirs is poorly characterized during initial development, so the largest uncertainty in mapping the fluid contact is the uncertainty in the distribution of the lithofacies. The position of the hydrocarbon-water contact may need to be confirmed by well penetration.