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Line 39: − + − − [[file:conducting-a-reservoir-simulation-study-an-overview_fig2.png|thumb|{{figure number|2}}(a) Pseudo-relative permeability and (b) capillary pressure curves calculated for two-layer thicknesses compared to laboratory measurements. (From <ref name=pt10r6>Coats, K. H., 1967, Simulation of three-dimensional, two-phase flow in oil and gas reservoirs: Society of Petroleum Engineers Journal, Dec., p. 377–388; Transactions, AIME, v. 240.</ref>; after <ref name=pt10r22 />; © 1967, 1990 Society of Petroleum Engineers.)]]
Reservoir simulation study (view source)
Revision as of 15:09, 21 January 2014
, 15:09, 21 January 2014→Preparing multiphase flow properties
==Preparing multiphase flow properties==
==Preparing multiphase flow properties==
[[file:conducting-a-reservoir-simulation-study-an-overview_fig2.png|thumb|{{figure number|2}}(a) Pseudo-relative permeability and (b) capillary pressure curves calculated for two-layer thicknesses compared to laboratory measurements. (From <ref name=pt10r6>Coats, K. H., 1967, Simulation of three-dimensional, two-phase flow in oil and gas reservoirs: Society of Petroleum Engineers Journal, Dec., p. 377–388; Transactions, AIME, v. 240.</ref>; after <ref name=pt10r22 />; © 1967, 1990 Society of Petroleum Engineers.)]]
Fluid saturations and the produced fractions of oil, gas, and water are determined by [[capillary pressure]]s and relative permeabilities specified as functions of water saturation. Equilibrium (initial) fluid saturations are directly dependent on capillary pressure, which is itself a function of height above the [[fluid contacts]], the fluid densities, porosities, permeabilities, and the surface chemistry of the fluids. Once production or injection commences, fluid movement is controlled by the [[relative permeability]] of each phase (except at very low velocities where the effects of capillary pressure are important). In a reservoir consisting of two fluid phases, oil-water, gas-oil, or gas-water capillary pressures and relative permeabilities must be specified. For a three-phase system, relative permeabilities and capillary pressures for two of the three possible systems are specified.
Fluid saturations and the produced fractions of oil, gas, and water are determined by [[capillary pressure]]s and relative permeabilities specified as functions of water saturation. Equilibrium (initial) fluid saturations are directly dependent on capillary pressure, which is itself a function of height above the [[fluid contacts]], the fluid densities, porosities, permeabilities, and the surface chemistry of the fluids. Once production or injection commences, fluid movement is controlled by the [[relative permeability]] of each phase (except at very low velocities where the effects of capillary pressure are important). In a reservoir consisting of two fluid phases, oil-water, gas-oil, or gas-water capillary pressures and relative permeabilities must be specified. For a three-phase system, relative permeabilities and capillary pressures for two of the three possible systems are specified.
[[Capillary pressure]] may be expressed using the ''Leverett J-function''. This function can be used to calculate capillary pressure as a function of each grid block's porosity and permeability. Sufficient data may also exist to correlate relative permeability curves' initial and residual saturations with porosity. Rather than assign individual capillary pressure and relative permeability curves for each grid block, average curves can be derived for several ranges of porosity and permeability values (also referred to as ''regions'').
[[Capillary pressure]] may be expressed using the ''Leverett J-function''. This function can be used to calculate capillary pressure as a function of each grid block's porosity and permeability. Sufficient data may also exist to correlate relative permeability curves' initial and residual saturations with porosity. Rather than assign individual capillary pressure and relative permeability curves for each grid block, average curves can be derived for several ranges of porosity and permeability values (also referred to as ''regions'').
[[Relative permeability]] and capillary pressures characterizing grid blocks may differ considerably from laboratory measurements. Laboratory measurements minimize the effects of gravity and heterogeneity. An example of these pseudo-relative permeabilities and capillary pressures is shown in Figure 2. The importance of gravity and heterogeneity effects is greater with larger layers. Pseudo-relative permeability and capillary pressure curves are often developed on small detailed studies for larger scale models. In some cases, pseudo-relative permeability and capillary pressure is developed during history matching. Pseudo-relative permeability and capillary pressure may be dependent on fluid and saturation history. Their ability to account correctly for gravity and heterogeneity is limited. Where these effects are significant, a smaller grid size should be used.
[[Relative permeability]] and capillary pressures characterizing grid blocks may differ considerably from laboratory measurements. Laboratory measurements minimize the effects of gravity and heterogeneity. An example of these pseudo-relative permeabilities and capillary pressures is shown in [[:file:conducting-a-reservoir-simulation-study-an-overview_fig2.png|Figure 2]]. The importance of gravity and heterogeneity effects is greater with larger layers. Pseudo-relative permeability and capillary pressure curves are often developed on small detailed studies for larger scale models. In some cases, pseudo-relative permeability and capillary pressure is developed during history matching. Pseudo-relative permeability and capillary pressure may be dependent on fluid and saturation history. Their ability to account correctly for gravity and heterogeneity is limited. Where these effects are significant, a smaller grid size should be used.
==Preparing matrix properties==
==Preparing matrix properties==