In petroleum engineering, TEM (true effective mobility), also called TEM-function developed by Abouzar Mirzaei-Paiaman, is a criterion to characterize dynamic two-phase flow characteristics of rocks (or dynamic rock quality).^{[1][2][3][4][5][6][7][8][9][10]} TEM is a function of relative permeability, porosity, absolute permeability and fluid viscosity, and can be determined for each fluid phase separately. TEM-function has been derived from Darcy's law for multiphase flow.^[1]

${\displaystyle {\mathit {TEM}}={\frac {kk_{\mathit {r}}}{\phi \mu }}}$

in which ${\displaystyle k}$ is the absolute permeability, ${\displaystyle k_{\mathit {r}}}$ is the relative permeability, φ is the porosity, and μ is the fluid viscosity. Rocks with better fluid dynamics (i.e., experiencing a lower pressure drop in conducting a fluid phase) have higher TEM versus saturation curves. Rocks with lower TEM versus saturation curves resemble low quality systems.^[1]

TEM-function in analyzing relative permeability data is analogous with Leverett J-function in analyzing capillary pressure data. Furthermore, TEM-function in two-phase flow systems is an extension of RQI (rock quality index) for single-phase systems.^[1]

Also, TEM-function can be used for averaging relative permeability curves (for each fluid phase separately, i.e., water, oil, gas, CO₂).^[1]

${\displaystyle {\text{Average kr}}={\frac {\sum _{i=1}^{n}{\mathit {TEM}}_{i}}{\sum _{i=1}^{n}\left({\frac {k}{\phi \mu }}\right)_{i}}}={\frac {\sum _{i=1}^{n}\left({\frac {kk_{\mathit {r}}}{\phi \mu }}\right)_{i}}{\sum _{i=1}^{n}\left({\frac {k}{\phi \mu }}\right)_{i}}}}$

See also

• Lak wettability index
• USBM wettability index

References