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Line 21: − − [[file:fluid-contacts_fig1.png|thumb|{{figure number|1}}Contact definitions and relationship of contacts in a pool (right) to reservoir capillary pressure and fluid production curves (left). The free water surface is the highest elevation with the same oil and water pressure (zero capillary pressure). The oil-water contact corresponds to the displacement pressure (DP) on the capillary pressure curve. The transition zone is the interval with co-production of water and hydrocarbons. The fraction of co-produced water is shown by the dashed line on the left. The gas-oil contact is controlled by the volume of gas in the trap, not the capillary properties.]] Line 92:
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[[file:fluid-contacts_fig1.png|thumb|300px|{{figure number|1}}Contact definitions and relationship of contacts in a pool (right) to reservoir capillary pressure and fluid production curves (left). The free water surface is the highest elevation with the same oil and water pressure (zero capillary pressure). The oil-water contact corresponds to the displacement pressure (DP) on the capillary pressure curve. The transition zone is the interval with co-production of water and hydrocarbons. The fraction of co-produced water is shown by the dashed line on the left. The gas-oil contact is controlled by the volume of gas in the trap, not the capillary properties.]]
Positions of initial [http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=fluid%20contact fluid contacts] are critical for field reserve estimates and for field development. Typically, the position of fluid contacts are first determined within control wells and then extrapolated to other parts of the field.
Positions of initial [http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=fluid%20contact fluid contacts] are critical for field reserve estimates and for field development. Typically, the position of fluid contacts are first determined within control wells and then extrapolated to other parts of the field.
[[file:Core-handling_large.png|thumb]]
[[file:Core-handling_large.png|thumb]]
==Methods for determining fluid contacts==
==Methods for determining fluid contacts==
===Hydrodynamic gradients===
===Hydrodynamic gradients===
[[file:fluid-contacts_fig3.png|thumb|{{figure number|3}}Example of calculating hydrodynamic fluid contacts from pressure data. Pressure elevations are shown by arrows. Calculated fluid contacts are shown by thin lines.]]
[[file:fluid-contacts_fig3.png|300px|thumb|{{figure number|3}}Example of calculating hydrodynamic fluid contacts from pressure data. Pressure elevations are shown by arrows. Calculated fluid contacts are shown by thin lines.]]
A common type of nonhorizontal oil-water contact is tilting in response to hydrodynamics, the movement of water in the reservoir interval. Hydrodynamic conditions that affect fluid contacts are usually associated with active [[meteoric aquifer]]s at relatively shallow depths. Indications of active [[meteoric flow]] include low salinity water, high topographic relief, and proximity to [[recharge]] areas.
A common type of nonhorizontal oil-water contact is tilting in response to hydrodynamics, the movement of water in the reservoir interval. Hydrodynamic conditions that affect fluid contacts are usually associated with active [[meteoric aquifer]]s at relatively shallow depths. Indications of active [[meteoric flow]] include low salinity water, high topographic relief, and proximity to [[recharge]] areas.
===Reservoir heterogeneity===
===Reservoir heterogeneity===
[[file:fluid-contacts_fig4.png|thumb|{{figure number|4}}Effect of reservoir heterogeneity on fluid contacts. (a) [[Capillary pressure]] curves for facies A and B within the reservoir. The dashed line corresponds to the saturation trend of the well In part (b). Sharp changes in saturation correspond to elevations of facies changes. (b) Oil-water contact corresponding to capillary pressure curves. The free water surface (''f''<sub>w</sub>) is the same for all facies, but the different displacement pressure results in different oil-water contact elevations (thick arrows). The transition zones will also have different thicknesses due to different [[relative permeability]] characteristics not shown here. The vertical line is the well position corresponding to the saturation profile shown in part (a).]]
[[file:fluid-contacts_fig4.png|300px|thumb|{{figure number|4}}Effect of reservoir heterogeneity on fluid contacts. (a) [[Capillary pressure]] curves for facies A and B within the reservoir. The dashed line corresponds to the saturation trend of the well In part (b). Sharp changes in saturation correspond to elevations of facies changes. (b) Oil-water contact corresponding to capillary pressure curves. The free water surface (''f''<sub>w</sub>) is the same for all facies, but the different displacement pressure results in different oil-water contact elevations (thick arrows). The transition zones will also have different thicknesses due to different [[relative permeability]] characteristics not shown here. The vertical line is the well position corresponding to the saturation profile shown in part (a).]]
[[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|300px|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 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.
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.