TEM-function

In petroleum engineering, true effective mobility (TEM), also called TEM-function is a criterion to characterize dynamic two-phase flow characteristics of rocks (or dynamic rock quality). 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. T E M = k k r ϕ μ {\displaystyle {\mathit {TEM}}={\frac {kk_{\mathit {r}}}{\phi \mu }}} in which k {\displaystyle k} is the absolute permeability, k r {\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. 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. Also, TEM-function can be used for averaging relative permeability curves (for each fluid phase separately, i.e., water, oil, gas, CO2). Average kr = ∑ i = 1 n T E M i ∑ i = 1 n ( k ϕ μ ) i = ∑ i = 1 n ( k k r ϕ μ ) i ∑ i = 1 n ( k ϕ μ ) i {\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}}}}

Measurement in petroleum engineering

In petroleum engineering, true effective mobility (TEM), also called TEM-function 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]

T E M = k k r ϕ μ {\displaystyle {\mathit {TEM}}={\frac {kk_{\mathit {r}}}{\phi \mu }}}

in which k {\displaystyle k} is the absolute permeability, k r {\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]

Average kr = ∑ i = 1 n T E M i ∑ i = 1 n ( k ϕ μ ) i = ∑ i = 1 n ( k k r ϕ μ ) i ∑ i = 1 n ( k ϕ μ ) i {\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

[edit]

• Lak wettability index
• USBM wettability index

References

[edit]

1. ^ ^{a b c d e} Mirzaei-Paiaman, A.; Saboorian-Jooybari, H.; Chen, Z.; Ostadhassan, M. (2019). "New technique of True Effective Mobility (TEM-Function) in dynamic rock typing: Reduction of uncertainties in relative permeability data for reservoir simulation". Petroleum Research. 179: 210–227. doi:10.1016/j.petrol.2019.04.044. S2CID 149962022.
2. ^ Mirzaei-Paiaman, A.; Asadolahpour, S.R.; Saboorian-Jooybari, H.; Chen, Z.; Ostadhassan, M. (2020). "A new framework for selection of representative samples for special core analysis". Petroleum Research. 5 (3): 210–226. doi:10.1016/j.ptlrs.2020.06.003.
3. ^ Mirzaei-Paiaman, A. (2019). "New Concept of Dynamic Rock Typing and Necessity of Modifying Current Reservoir Simulators" (PDF). SPE Review London: 7–10. Retrieved 6 August 2020.
4. ^ Faramarzi-Palangar, M. (2020). "Investigating dynamic rock quality in two-phase flow systems using TEM-function: A comparative study of different rock typing indices". Petroleum Research. 6: 16–25. doi:10.1016/j.ptlrs.2020.08.001.
5. ^ Wang, R. (2019). "Grid density overlapping hierarchical algorithm for clustering of carbonate reservoir rock types: A case from Mishrif Formation of West Qurna-1 oilfield, Iraq". Journal of Petroleum Science and Engineering. 182 106209. doi:10.1016/j.petrol.2019.106209. S2CID 198327827.
6. ^ Noorbakhsh, A. (2020). "Field Production Optimization Using Sequential Quadratic Programming (SQP) Algorithm in ESP-Implemented Wells, A Comparison Approach". Journal of Petroleum Science and Technology. Retrieved 6 August 2020.
7. ^ Nazari, M.H. (2019). "Investigation of factors influencing geological heterogeneity in tight gas carbonates, Permian reservoir of the Persian Gulf". Journal of Petroleum Science and Engineering. 183 106341. doi:10.1016/j.petrol.2019.106341. S2CID 202080296.
8. ^ Liu, Y. (2019). "Petrophysical static rock typing for carbonate reservoirs based on mercury injection capillary pressure curves using principal component analysis". Journal of Petroleum Science and Engineering. 181: 106175. doi:10.1016/j.petrol.2019.06.039. S2CID 197095683.
9. ^ Shakiba, M. (2020). "An experimental investigation of the proportion of mortar components on physical and geomechanical characteristics of unconsolidated artificial reservoir sandstones". Journal of Petroleum Science and Engineering. 189 107022. doi:10.1016/j.petrol.2020.107022. S2CID 214481575.
10. ^ Huang, R. (2020). "Research on Dynamic Simulation System of Multidimensional Reservoirs". 2020 IEEE International Conference on Power, Intelligent Computing and Systems (ICPICS). pp. 96–99. doi:10.1109/ICPICS50287.2020.9202339. ISBN 978-1-7281-9874-3. S2CID 221914057.

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