Changes

Positions of initial 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 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.

Definitions of fluid contacts are based on comparison to [[capillary pressure]] curves (Figure 1) (see “[[Capillary pressure]]”). The ''free water surface'' is the highest elevation at which the pressure of the hydrocarbon phase is the same as that of water. The ''hydrocarbon-water'' (''oil-water'' or ''gas-water'') ''contact'' is the lowest elevation at which mobile hydrocarbons occur. The ''transition zone'' is the elevation range in which water is coproduced with hydrocarbons. The ''gas-oil contact'' is the elevation above which gas is the produced hydrocarbon phase.

Definitions of fluid contacts are based on comparison to [[capillary pressure]] curves (Figure 1) (see [[Capillary pressure]]). The ''free water surface'' is the highest elevation at which the pressure of the hydrocarbon phase is the same as that of water. The ''hydrocarbon-water'' (''oil-water'' or ''gas-water'') ''contact'' is the lowest elevation at which mobile hydrocarbons occur. The ''transition zone'' is the elevation range in which water is coproduced with hydrocarbons. The ''gas-oil contact'' is the elevation above which gas is the produced hydrocarbon phase.

[[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.]]

[[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.]]

==Methods for determining fluid contacts==

==Methods for determining fluid contacts==

Methods for determining initial fluid contacts are listed in Table 1 and are discussed by Bradley (1987). These include fluid sampling methods, saturation estimation from wireline logs, estimation from conventional and sidewall cores, and pressure methods. Once initial fluid contact elevations in control wells are determined, the contacts in other parts of the reservoir can be estimated. Initial fluid contacts within most reservoirs having a high degree of continuity are almost horizontal, so the reservoir fluid contact elevations are those of the control wells.

Methods for determining initial fluid contacts are listed in Table 1 and are discussed by [[Bradley (1987)]]. These include fluid sampling methods, saturation estimation from wireline logs, estimation from conventional and sidewall cores, and pressure methods. Once initial fluid contact elevations in control wells are determined, the contacts in other parts of the reservoir can be estimated. Initial fluid contacts within most reservoirs having a high degree of continuity are almost horizontal, so the reservoir fluid contact elevations are those of the control wells.

{| class = "wikitable"

{| class = "wikitable"

* Hydrodynamic gradients

* Hydrodynamic gradients

* Reservoir heterogeneity (see “[[Geological heterogeneities]]”)

* Reservoir heterogeneity (see [[Geological heterogeneities]])

* Semipermeable barriers

* Semipermeable barriers

| Semipermeable barriers

| Semipermeable barriers

| Semipermeable barriers compartmentalize an otherwise homogeneous reservoir

| Semipermeable barriers compartmentalize an otherwise homogeneous reservoir

| Fluid contacts horizontal, yet at different elevations in different parts of the pool All types of fluid contacts affected Barriers are documented in locations which might cause observed compartmentalization Contact changes do not correspond to regional hydrodynamics or changes in caDillarv DroDerties

| Fluid contacts horizontal, yet at different elevations in different parts of the pool; All types of fluid contacts affected Barriers are documented in locations which might cause observed compartmentalization; Contact changes do not correspond to regional hydrodynamics or changes in capillary properties

|}

|}

If purely hydrodynamic in origin, the fluid contact tilt can be extrapolated across the field as a flat plane that intersects the contact elevation in a minimum of three control wells. Regional fluid pressure data can be used to extrapolate the fluid contacts from the contacts measured in one or two wells. Only corrected shut-in pressures unaffected by nearby production should be used for this evaluation.

If purely hydrodynamic in origin, the fluid contact tilt can be extrapolated across the field as a flat plane that intersects the contact elevation in a minimum of three control wells. Regional fluid pressure data can be used to extrapolate the fluid contacts from the contacts measured in one or two wells. Only corrected shut-in pressures unaffected by nearby production should be used for this evaluation.

Hydrodynamic potential (''h'') is usually measured as the elevation to which water would rise in an open borehole, called the ''Potentiometric elevation''. It is calculated from the reservoir pressure by the following relationship:<disp-formula id="FluidContactseq1"><tex-math notation="TeX">$$\begin{align}h = P/(\rho_{\rm w} \times C) + (E_{\rm m} - E_{\rm r}) \label{978-1-62981-110-9_260_eq1(1)}\end{align}$$</tex-math></disp-formula> (1)

Hydrodynamic potential (''h'') is usually measured as the elevation to which water would rise in an open borehole, called the ''Potentiometric elevation''. It is calculated from the reservoir pressure by the following relationship:<br><math>h = P/(\rho_{\rm w} \times C) + (E_{\rm m} - E_{\rm r}) </math>

where

where

[[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''_w) 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|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''_w) 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).]]

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,, 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 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 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.

===Semipermeable fluid barriers===

===Semipermeable fluid barriers===

Semipermeable barriers can divide a reservoir into compartments with different fluid contacts even if the capillary properties of the reservoir rock are the same on both sides of the barrier. Semipermeable barriers can include faults, mineralized fractures, or semipermeable beds. The resulting pool has horizontal fluid contacts, but the contacts occur at different elevations on different sides of the barrier (Figure 5). The elevation difference between fluid contacts is related to the displacement pressure of the semipermeable barrier<ref name=pt06r151>Watts, N. L., 1987, Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns: Marine and Petroleum Geology, v. 4, p. 274–307., 10., 1016/0264-8172(87)90008-0</ref>. Whereas fault or mineralized fracture compartmentalization is not readily recognized without detailed mapping, semipermeable beds are commonly recognized and the reservoir is separated into different pools corresponding to the different fluid contacts. Once the position of the barrier is mapped and the elevations of the contact on either side are determined from control wells, the fluid contacts can be mapped as horizontal surfaces within each compartment of the pool. Limited communication across semipermeable barriers is possible during production from the pool.

Semipermeable barriers can divide a reservoir into compartments with different fluid contacts even if the capillary properties of the reservoir rock are the same on both sides of the barrier. Semipermeable barriers can include faults, mineralized fractures, or semipermeable beds. The resulting pool has horizontal fluid contacts, but the contacts occur at different elevations on different sides of the barrier (Figure 5). The elevation difference between fluid contacts is related to the displacement pressure of the semipermeable barrier.<ref name=pt06r151>Watts, N. L., 1987, Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns: Marine and Petroleum Geology, v. 4, p. 274–307., 10., 1016/0264-8172(87)90008-0</ref> Whereas fault or mineralized fracture compartmentalization is not readily recognized without detailed mapping, semipermeable beds are commonly recognized and the reservoir is separated into different pools corresponding to the different fluid contacts. Once the position of the barrier is mapped and the elevations of the contact on either side are determined from control wells, the fluid contacts can be mapped as horizontal surfaces within each compartment of the pool. Limited communication across semipermeable barriers is possible during production from the pool.

[[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.]]