Gassmann Fluid Substitution

Description Calculate new density, P-velocity, and S-velocity curves using the Gassmann Equation.
Module(s) Explorationist
Requirements
Related
Works with

This process calculates new density, P-velocity, and S-velocity curves using the Gassmann Equation. Gassmann is an equation to derive P-velocity, S-velocity and density in a rock medium in which the original fluid was replaced by another fluid (fluid substitution).

  1. In the Control Panel, go to View New Single Well View.
  2. In the Single Well window, open the Process tab.
  3. At the tab header, click the blue "+" icon.
  4. Click Gassmann Fluid Substitution.
  5. Type a name for the process and click OK.

Configure the Gassmann Fluid Substitution process

  1. Input
    1. Curves:
      1. Velocity type:
        • Velocity: Select to calculate from velocity curves
        • Slowness: Select to calculate from sonic logs (slowness)
      2. Curve selection: Choose a curve for each entry (P Velocity or P Slowness, S Velocity or S Slowness, Density). The available Vp/Vs curves depend on the chosen velocity type.
  2. Modelling zone: Set the Start and End of the interval over which to perform the fluid substitution. For each boundary, select the reference type from the dropdown:
    • Top of well: Uses the shallowest measured depth of the well (minimum MD) as the base. An optional offset (in project units) can be added. The resulting depth is displayed alongside the field.
    • TD of well: Uses the total depth of the well (maximum MD) as the base. An optional offset (in project units) can be added. The resulting depth is displayed alongside the field.
    • Depth (MDKB) or Depth (TVDSS/TVDBML): Enter a depth value directly in the chosen depth domain.
    • Horizon: Select a horizon from the project. The depth is derived from the horizon's intersection with the well.
    • Marker: Select a marker (well top) from the well.
  3. Porosity input: Specifies how porosity is provided for the calculation. Select one of three options:
    • Use Porosity curve: Select a porosity curve as the input.
    • Use Density curve: Select to derive porosity from the density curve.
    • Constant value: Specify a single constant porosity value (%) to use across the reservoir interval.
  1. Matrix fraction input: Define one or more minerals that make up the rock matrix. Each mineral has:
    • Name: A label for the mineral (e.g. Quartz, Calcite, Clay).
    • Density (g/cm³): Density of the mineral.
    • Bulk modulus (GPa): Bulk modulus of the mineral.
    • Shear modulus (GPa): Shear modulus of the mineral.
    • Preset: Quickly populate density, bulk modulus, and shear modulus from a preset mineral types (Sandstone, Limestone, Carbonate, and Claystone)

Minerals can be added using the blue (+) button and removed using the red (x) button. At least one mineral must remain.

  1. Composition:
    • Weight: Specify the relative weight of each mineral.
    • Volume fraction: Displays percentage for each fraction normalised to 100%.
    • Averaging method: Select either Voigt-Reuss-Hill or Reuss averaging method.
  2. Mineral info: Dynamically displays the calculated composite matrix properties—density (ρ), bulk modulus (K), and shear modulus (G).
  1. Fluid saturation setting: Defines the fluid phases used in the substitution.
    • Water: Specify the properties of the water phase:
    • Density (g/cm³): Density of water.
    • Bulk modulus (GPa): Bulk modulus of water.
    • Hydrocarbons: Define one or more hydrocarbon fluid phases. Each phase has:
      • Name: A label for the fluid phase (e.g. Oil, Gas, Condensate).
      • Density (g/cm³): Density of the fluid phase.
      • Bulk modulus (GPa): Bulk modulus of the fluid phase.
      • Preset: Quickly populate density and bulk modulus from a built-in preset (Oil, Gas, Condensate, Heavy oil).

Fluid phases can be added using the blue (+) button and removed using the red (x) button. At least one phase must remain.

  1. Gassmann substitution scenarios: Specify the relative saturation of water and hydrocarbon phases. The displayed percentage shows each weight normalised to 100%.
    • In-situ fluid: The expected relative saturation of water and hydrocarbon fluid phases in the recorded well data.
    • Substitution fluid: The relative replacement saturation of water and the hydrocarbon fluid phases.
  2. Fluid info: Displays the input density (ρ) and bulk modulus (K) values for both the original in-situ fluid and the target substitution fluid.
  1. Output
    • Curves
      • Enable custom name: Specify the name of the output curves. Each curve will be named as "[output class]_[process name]" by default, or if a custom name is supplied, "[output class]_[custom name]".
      • Extent: Specify the extents of the output curves.