Relative permeability

In multiphase flow in porous media, the relative permeability of a phase is a dimensionless measure of the effective permeability of that phase. It is the ratio of the effective permeability of that phase to the absolute permeability. It can be viewed as an adaptation of Darcy's law to multiphase flow.

For two-phase flow in porous media given steady-state conditions, we can write

${\displaystyle q_{i}=-{\frac {k_{i}}{\mu _{i}}}\nabla P_{i}\qquad {\text{for}}\quad i=1,2}$

where ${\displaystyle q_{i}}$ is the flux, ${\displaystyle \nabla P_{i}}$ is the pressure drop, ${\displaystyle \mu _{i}}$ is the viscosity. The subscript ${\displaystyle i}$ indicates that the parameters are for phase ${\displaystyle i}$.

${\displaystyle k_{i}}$ is here the phase permeability (i.e., the effective permeability of phase ${\displaystyle i}$), as observed through the equation above.

Relative permeability, ${\displaystyle k_{\mathit {ri}}}$, for phase ${\displaystyle i}$ is then defined from ${\displaystyle k_{i}=k_{\mathit {ri}}k}$, as

${\displaystyle k_{\mathit {ri}}=k_{i}/k}$

where ${\displaystyle k}$ is the permeability of the porous medium in single-phase flow, i.e., the absolute permeability. Relative permeability must be between zero and one.

In applications, relative permeability is often represented as a function of water saturation; however, owing to capillary hysteresis one often resorts to a function or curve measured under drainage and another measured under imbibition.

Under this approach, the flow of each phase is inhibited by the presence of the other phases. Thus the sum of relative permeabilities over all phases is less than 1. However, apparent relative permeabilities larger than 1 have been obtained since the Darcean approach disregards the viscous coupling effects derived from momentum transfer between the phases (see assumptions below). This coupling could enhance the flow instead of inhibit it. This has been observed in heavy oil petroleum reservoirs when the gas phase flows as bubbles or patches (disconnected). [1]

Modelling assumptions

The above form for Darcy's law is sometimes also called Darcy's extended law, formulated for horizontal, one-dimensional, immiscible multiphase flow in homogeneous and isotropic porous media. The interactions between the fluids are neglected, so this model assumes that the solid porous media and the other fluids form a new porous matrix through which a phase can flow, implying that the fluid-fluid interfaces remain static in steady-state flow, which is not true, but this approximation has proven useful anyway.

Each of the phase saturations must be larger than the irreducible saturation, and each phase is assumed continuous within the porous medium.

Based on data from special core analysis laboratory (SCAL) experiments,[2] simplified models of relative permeability as a function of saturation (e.g. water saturation) can be constructed. This article will focus on an oil-water system.

Saturation scaling

Water saturation ${\displaystyle S_{\mathit {w}}}$ is the fraction of porevolume that is filled with water, and similar for oil saturation ${\displaystyle S_{\mathit {o}}}$. Thus, saturations are in itselves scaled properties or variables. This gives the constraint

${\displaystyle S_{\mathit {w}}+S_{\mathit {o}}=1\Leftrightarrow S_{\mathit {w}}=1-S_{\mathit {o}}}$

The model functions or correlations for relative permealities in an oil-water system are therefore usually written as functions of only water saturation, and this makes it natural to select water saturation as the horizontal axis in graphical presentations. Let ${\displaystyle S_{\mathit {wir}}}$ (also denoted ${\displaystyle S_{\mathit {wc}}}$ and sometimes ${\displaystyle S_{\mathit {wr}}}$) be the irreducible (or minimal or connate) water saturation, and let ${\displaystyle S_{\mathit {orw}}}$ be the residual (minimal) oil saturation after water flooding (imbibition). The flowing water saturation window in a water invasion / injection / imbibition process is bounded by a minimum value ${\displaystyle S_{\mathit {wir}}}$ and a maximum value ${\displaystyle S_{\mathit {wor}}=1-S_{\mathit {orw}}}$. In mathematical terms the flowing saturation window is written as

${\displaystyle S_{\mathit {wir}}\leq S_{\mathit {w}}\leq S_{\mathit {wor}}=1-S_{\mathit {orw}}}$

Normalization of water saturation values

By scaling the water saturation to the flowing saturation window, we get a (new or another) normalized water saturation value

${\displaystyle S_{\mathit {wn}}=S_{\mathit {wn}}(S_{w})={\frac {S_{w}-S_{\mathit {wir}}}{1-S_{\mathit {wir}}-S_{\mathit {orw}}}}={\frac {S_{w}-S_{\mathit {wir}}}{S_{\mathit {wor}}-S_{\mathit {wir}}}}}$

and a normalized oil saturation value

${\displaystyle S_{\mathit {on}}=1-S_{\mathit {wn}}={\frac {S_{o}-S_{\mathit {orw}}}{1-S_{\mathit {wir}}-S_{\mathit {orw}}}}}$

Endpoints

Let ${\displaystyle K_{\mathit {row}}}$ be oil relative permeability, and let ${\displaystyle K_{\mathit {rw}}}$ be water relative permeability. There are two ways of scaling phase permeability (i.e. effective permeability of the phase). If we scale phase permeability w.r.t. absolute water permeability (i.e. ${\displaystyle S_{\mathit {w}}=1}$), we get an endpoint parameter for both oil and water relative permeability. If we scale phase permeability w.r.t. oil permeability with irreducible water saturation present, ${\displaystyle K_{\mathit {row}}}$ endpoint is one, and we are left with only the ${\displaystyle K_{\mathit {rw}}}$ endpoint parameter. In order to satisfy both options in the mathematical model, it is common to use two endpoint symbols in the model for two-phase relative permeability. The endpoints / endpoint parameters of oil and water relative permeabilities are

${\displaystyle {\begin{aligned}K_{\mathit {row}}(S_{\mathit {wir}})=K_{\mathit {rot}}&&and&&K_{\mathit {rw}}(S_{\mathit {wor}})=K_{\mathit {rwr}}\end{aligned}}}$

These symbols have their merits and limits. The symbol ${\displaystyle K_{\mathit {rot}}}$ emphasize that it represents the top point of ${\displaystyle K_{\mathit {row}}}$. It occurs at irreducible water saturation, and it is the largest value of ${\displaystyle K_{\mathit {row}}}$ that can occur for initial water saturation. The competing endpoint symbol ${\displaystyle K_{\mathit {ror}}}$ occurs in imbibition flow in oil-gas systems. If the permeability basis is oil with irreducible water present, then ${\displaystyle K_{\mathit {rot}}=1}$. The symbol ${\displaystyle K_{\mathit {rwr}}}$ emphasizes that it is occurring at the residual oil saturation. An alternative symbol to ${\displaystyle K_{\mathit {rwr}}}$ is ${\displaystyle K_{\mathit {rw}}^{o}}$ which emphasizes that the reference permeability is oil permeability with irreducible water ${\displaystyle S_{\mathit {wir}}}$ present.

The oil and water relative permeability models are then written as

${\displaystyle {\begin{aligned}K_{\mathit {row}}=K_{\mathit {rot}}\cdot K_{\mathit {rown}}(S_{\mathit {wn}})&&and&&K_{\mathit {rw}}=K_{\mathit {rwr}}\cdot K_{\mathit {rwn}}(S_{\mathit {wn}})\end{aligned}}}$

The functions ${\displaystyle K_{\mathit {rown}}}$ and ${\displaystyle K_{\mathit {rwn}}}$ are called normalised relative permeabilities or shape functions for oil and water, respectively. The endpoint parameters ${\displaystyle K_{\mathit {rot}}}$ and ${\displaystyle K_{\mathit {rwr}}}$ (which is a simplification of ${\displaystyle K_{\mathit {rwor}}}$) are physical properties that are obtained either before or together with the optimization of shape parameters present in the shape functions.

There are often many symbols in articles that discuss relative permeability models and modelling. A number of busy core analysts, reservoir engineers and scientists often skip using tedious and time-consuming subscripts, and write e.g. Krow instead of ${\displaystyle K_{\mathit {row}}}$ or ${\displaystyle k_{\mathit {row}}}$ or krow or oil relative permeability. A variety of symbols are therefore to be expected, and accepted as long as they are explained or defined.

The effects that slip or no-slip boundary conditions in pore flow have on endpoint parameters, are discussed by Berg et alios .[3][4]

Corey-model

An often used approximation of relative permeability is the Corey correlation [5] [6] [7] which is a power law in saturation. The Corey correlations of the relative permeability for oil and water are then

Example of Corey-correlation for imbibition flow with ${\displaystyle N_{\mathit {o}}}$ = ${\displaystyle N_{\mathit {w}}=2}$ and ${\displaystyle K_{\mathit {rwr}}=0.6}$.

${\displaystyle K_{\mathit {row}}(S_{w})=K{_{\mathit {rot}}}(1-S_{\mathit {wn}})^{N_{\mathit {o}}}}$

${\displaystyle \,\,K_{\mathit {rw}}(S_{w})=K{_{\mathit {rwr}}}S_{\mathit {wn}}^{N_{\mathit {w}}}}$

If the permeability basis is normal oil with irreducible water present, then ${\displaystyle K_{\mathit {rot}}=1}$.

The empirical parameters ${\displaystyle N_{\mathit {o}}}$ and ${\displaystyle N_{\mathit {w}}}$ are called curve shape parameters or simply shape parameters, and they can be obtained from measured data either by analytical interpretation of measured data, or by optimization using a core flow numerical simulator to match the experiment (often called history matching). ${\displaystyle N_{\mathit {o}}}$ = ${\displaystyle N_{\mathit {w}}=2}$ is sometimes appropriate. The physical properties ${\displaystyle K_{\mathit {rot}}}$ and ${\displaystyle K_{\mathit {rwr}}}$ are obtained either before or together with the optimizing of ${\displaystyle N_{\mathit {o}}}$ and ${\displaystyle N_{\mathit {w}}}$.

In case of gas-water system or gas-oil system there are Corey correlations similar to the oil-water relative permeabilities correlations shown above.

LET-model

The Corey-correlation or Corey model has only one degree of freedom for the shape of each relative permeability curve, the shape parameter N. The LET-correlation[8] [9] adds more degrees of freedom in order to accommodate the shape of relative permeability curves in SCAL experiments[2] and in 3D reservoir models that are adjusted to match historic production. These adjustments frequently includes relative permeability curves and endpoints.

Example of LET-correlation for imbibition flow with L,E,T all equal to 2 and ${\displaystyle K_{\mathit {rwr}}=0.6}$.

The LET-type approximation is described by 3 parameters L, E, T. The correlation for water and oil relative permeability with water injection is thus

${\displaystyle K_{\mathit {rw}}={\frac {{K_{\mathit {rwr}}}S_{\mathit {wn}}^{L_{\mathit {w}}}}{{S_{\mathit {wn}}}^{L_{\mathit {w}}}+{E_{\mathit {w}}}{(1-S_{\mathit {wn}})}^{T_{\mathit {w}}}}}}$

and

${\displaystyle K_{\mathit {row}}={\frac {K_{\mathit {rot}}(1-S_{\mathit {wn}})^{L_{o}}}{{(1-S_{\mathit {wn}})^{L_{o}}}+{E_{\mathit {o}}}S_{\mathit {wn}}^{T_{\mathit {o}}}}}}$

written using the same ${\displaystyle S_{w}}$ normalization as for Corey.

Only ${\displaystyle S_{\mathit {wir}}}$ , ${\displaystyle S_{\mathit {orw}}}$ , ${\displaystyle K_{\mathit {rot}}}$ and ${\displaystyle K_{\mathit {rwr}}}$ have direct physical meaning, while the parameters L, E and T are empirical. The parameter L describes the lower part of the curve, and by similarity and experience the L-values are comparable to the appropriate Corey parameter. The parameter T describes the upper part (or the top part) of the curve in a similar way that the L-parameter describes the lower part of the curve. The parameter E describes the position of the slope (or the elevation) of the curve. A value of one is a neutral value, and the position of the slope is governed by the L- and T-parameters. Increasing the value of the E-parameter pushes the slope towards the high end of the curve. Decreasing the value of the E-parameter pushes the slope towards the lower end of the curve. Experience using the LET correlation indicates the following reasonable ranges for the parameters L, E, and T: L ≥ 0.1, E > 0 and T ≥ 0.1.

In case of gas-water system or gas-oil system there are LET correlations similar to the oil-water relative permeabilities correlations shown above.

Evaluations

After Morris Muskat et alios established the concept of relative permeability in late 1930'ies, the number of correlations, i.e. models, for relative permeability has steadily increased. This creates a need for evaluation of the most common correlations at the current time. Two of the latest (per 2019) and most thorough evaluations are done by Moghadasi et alios[10] and by Sakhaei et alios.[11] Moghadasi et alios[10] evaluated Corey, Chierici and LET correlations for oil/water relative permeability using a sophisticated method that takes into account the number of uncertain model parameters. They found that LET, with the largest number (three) of uncertain parameters, was clearly the best one for both oil and water relative permeability. Sakhaei et alios[11] evaluated 10 common and widely used relative permeability correlations for gas/oil and gas/condensate systems, and found that LET showed best agreement with experimental values for both gas and oil/condensate relative permeability.

Relative permeability versus TEM-function

Relative permeability is just one of the factors that affect fluid flow dynamics, and therefore can’t fully capture dynamic flow behavior of porous media.[12][13][14] A criterion/metric has been established to characterize dynamic characteristics of rocks, known as True Effective Mobility or TEM-function.[13][14] TEM-function is a function of Relative permeability, Porosity, 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.[13]

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

in which k is the permeability, kr 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.[13]

While TEM-function controls the dynamic behavior of a system, the Relative permeability alone has conventionally been used to classify different fluid flow systems. Despite Relative permeability is itself a function of several parameters including permeability, Porosity and Viscosity, the dynamic behavior of systems may not necessarily be fully captured by this single source of information and, if used, it can even result in misleading interpretations.[13][14]

TEM-function in analyzing Relative permeability data is analogous with Leverett J-function in analyzing Capillary pressure data.[13]

Averaging Relative permeability curves

In multiphase systems Relative permeability curves of each fluid phase (i.e., water, oil, gas, CO2) can be averaged using the concept of TEM-function as:[13]

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

See also

• TEM-function
• Permeability (earth sciences)
• Capillary pressure
• Imbibition
• Drainage
• Buckley–Leverett equation

References

1. Bravo, M.C.; Araujo, M. (2008). "Analysis of the Unconventional Behavior of Oil Relative Permeability during Depletion Tests of Gas-Saturated Heavy Oils". International Journal of Multiphase Flow. 34 (5): 447–460. doi:10.1016/j.ijmultiphaseflow.2007.11.003.
2. McPhee, C.; Reed, J.; Zubizarreta, I. (2015). Core Analysis: A Best Practice Guide. Elsevier. ISBN 978-0-444-63533-4.
3. Berg, S.; Cense, A.W.; Hofman, J.P.; Smits, R.M.M. (2007). "Flow in Porous Media with Slip Boundary Condition". Paper SCA2007-13 presented at the 2007 International Symposium of the SCA, Calgary, Canada, 10 - 12 September, 2007.
4. Berg, S.; Cense, A.W.; Hofman, J.P.; Smits, R.M.M. (2008). "Two-Phase Flow in Porous Media with Slip Boundary Condition". Transport in Porous Media. 74: 275–292. doi:10.1007/s11242-007-9194-4.
5. Goda, H.M.; Behrenbruch, P. (2004). Using a Modified Brooks-Corey Model to Study Oil-Water Relative Permeability for Diverse Pore Structures. Paper SPE-88538-MS Presented at SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia. doi:10.2118/88538-MS. ISBN 978-1-55563-979-2.
6. Brooks, R.H.; Corey, A.T. (1964). "Hydraulic properties of porous media". Hydrological Papers. 3.
7. Corey, A.T. (Nov 1954). "The Interrelation Between Gas and Oil Relative Permeabilities". Prod. Monthly. 19 (1): 38–41.
8. Lomeland, F.; Ebeltoft, E.; Thomas, W.H. (2005). "A New Versatile Relative Permeability Correlation" (PDF). Proceedings of the 2005 International Symposium of the SCA, Abu Dhabi, United Arab Emirates, October 31 - November 2, 2005.
9. Lomeland, F. (2018). "Overview of the LET Family of Versatile Correlations for Flow Functions" (PDF). Proceedings of the 2018 International Symposium of the SCA, Trondheim, Norway, 27 - 30 August, 2018.
10. Moghadasi, L.; Guadagnini, A.; Inzoli, F.; Bartosek, M. (2015). "Interpretation of two-phase relative permeability curves through multiple formulations and model quality criteria". Journal of Petroleum Science and Engineering. 135: 738–749. doi:10.1016/j.petrol.2015.10.027. hdl:11311/968828.
11. Sakhaei, Z.; Azin, R.; Osfouri, S. (2016). "Assessment of empirical/theoretical relative permeability correlations for gas-oil/condensate systems". Paper Presented at the 1st Persian Gulf Oil, Gas and Petrochemical Biennal Conference Held at the Persian Gulf University In, Bushehr, Iran, 20 April, 2016.
12. Mirzaei-Paiaman, Abouzar; Ostadhassan, Mehdi; Rezaee, Reza; Saboorian-Jooybari, Hadi; Chen, Zhangxin (2018). "A new approach in petrophysical rock typing". Journal of Petroleum Science and Engineering. 166: 445–464. doi:10.1016/j.petrol.2018.03.075. hdl:20.500.11937/66997.
13. Mirzaei-Paiaman, Abouzar; Saboorian-Jooybari, Hadi; Chen, Zhangxin; Ostadhassan, Mehdi (2019). "New technique of True Effective Mobility (TEM-Function) in dynamic rock typing: Reduction of uncertainties in relative permeability data for reservoir simulation". Journal of Petroleum Science and Engineering. 179: 210–227. doi:10.1016/j.petrol.2019.04.044.
14. Mirzaei-Paiaman, Abouzar; Asadolahpour, Seyed Reza; Saboorian-Jooybari, Hadi; Chen, Zhangxin; Ostadhassan, Mehdi (2020). "A new framework for selection of representative samples for special core analysis". Petroleum Research. doi:10.1016/j.ptlrs.2020.06.003.

External links

• Relative Permeability Curves