Accurate determination of characteristic relative permeability curves

Krause, Michael; Benson, Sally M.

doi:10.1016/j.advwatres.2015.07.009

Cited by 64 publications

(76 citation statements)

References 72 publications

(95 reference statements)

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“…Core-flooding experiments are often performed at conditions where the capillary-to-viscous force balance which control flow can significantly change with parameters such as the flow rate or the fluid properties (Honarpour et al 1995;Reynolds and Krevor 2015;Krause and Benson 2015). It is important to perform experiments at various flow conditions to quantify how scales influence the results and extrapolate the results in a consistent manner (Huang et al 1995).…”

Section: Discussionmentioning

confidence: 99%

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

et al. 2017

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We examine the effect of capillary and viscous forces on the displacement of one fluid by a second, immiscible fluid across and along parallel layers of contrasting porosity, and relative permeability, as well as previously explored contrasts in absolute permeability and capillary pressure. We consider displacements with wetting, intermediate-wetting and non-wetting injected phases. Flow is characterized using six independent dimensionless numbers and a dimensionless storage efficiency, which is numerically equivalent to the recovery efficiency. Results are directly applicable to geologic carbon storage and hydrocarbon production. We predict how the capillary-viscous force balance influences storage efficiency as a function of a small number of key dimensionless parameters, and provide a framework to support mechanistic interpretations of complex field or experimental data, and numerical model predictions, through the use of simple dimensionless models. When flow is directed across layers, we find that capillary heterogeneity traps the non-wetting phase, regardless of whether it is the injected or displaced phase. However, minimal trapping occurs when the injected phase is intermediate-wetting or when high-permeability layers contain a smaller moveable volume of fluid than low-permeability layers. A dimensionless capillary-to-viscous number defined using the layer thickness rather than the more commonly used system length is most relevant to predict capillary heterogeneity trapping. When flow is directed along layers, we show that, regardless of wettability, increasing capillary crossflow reduces the distance between the leading edges of the injected phase in each layer and increases storage efficiency. This may be counter-intuitive when the injected phase is non-wetting. Crossflow has a significant impact on storage efficiency only when high-permeability layers contain a smaller moveable volume of fluid than low-permeability layers. In that case, capillary heterogeneity traps the wetting phase, regardless of whether it is the injected or displaced phase. B Yacine Debbabi

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Section: Discussionmentioning

confidence: 99%

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

et al. 2017

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“…A number of studies have shown how saturation heterogeneity, and thus relative permeability heterogeneity, will arise in rocks with small variations in capillary pressure characteristics (Ringrose et al, 1993;Honarpour et al, 1995;Huang et al, 1995;Egermann and Lenormand, 2005;Krause and Benson, 2015). These heterogeneities are often small enough (i.e.…”

Section: Introductionmentioning

confidence: 99%

“…at very high flow rates in homogeneous cores). Recent modelling efforts have similarly focused on deriving the viscous limit relative permeability from observations on heterogeneous rocks (Krause and Benson, 2015). In the approach presented here, the goal becomes to characterise a numerical rock core with accurate viscous limit properties, and use this to derive equivalent relative permeabilities at relevant reservoir and flow conditions, which are suitable for upscaling and field scale reservoir simulation.…”

Section: Introductionmentioning

confidence: 99%

“…The viscous limit relative permeability is often referred to as 'intrinsic' (Reynolds and Krevor, 2015), 'characteristic' (Krause and Benson, 2015), or as a 'rock curve' (Pickup and Stephen, 2000), due to its association with universality. However, as we will demonstrate in this work, the characterisation of a rock core solely with this viscous limit relative permeability has little relevance for the description of subsurface flow in heterogeneous rocks, and should be replaced with equivalent relative permeabilities derived on representative rocks at appropriate reservoir conditions.…”

Section: Introductionmentioning

confidence: 99%

“…We build on these experimental approaches and combine this with recently developed modelling techniques, primarily those of Krause (2012); Krause et al (2013); Krause and Benson (2015), to create a numerical representation of the rock core. The numerical models are then used to derive equivalent relative permeabilities at a range of conditions that are relevant to the subsurface.…”

Section: Introductionmentioning

confidence: 99%

See 2 more Smart Citations

Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Jackson¹,

Agada²,

Reynolds³

et al. 2017

Preprint

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In this work, we analyse the characterisation of drainage multiphase flow properties on heterogeneous rock cores using a rich experimental dataset and mm-m scale numerical simulations. Along with routine multiphase flow properties, 3D sub-metre scale capillary pressure heterogeneity is characterised by combining experimental observations and numerical calibration, resulting in a 3D numerical model of the rock core. The uniqueness and predictive capability of the numerical models are demonstrated by accurately predicting the experimentally measured relative permeability of N 2 -DI water and CO 2 -brine systems in two distinct sandstone rock cores across multiple fractional flow regimes and total flow rates. The numerical models are used to derive equivalent relative permeabilities, which are upscaled functions incorporating the effects of sub-metre scale capillary pressure. The functions are obtained across capillary numbers which span four orders of magnitude, representative of the range of flow regimes that occur in subsurface CO 2 injection. Removal of experimental boundary artefacts allows the derivation of equivalent functions which are characteristic of the continuous subsurface. We also demonstrate how heterogeneities can be re-orientated and restructured efficiently to obtain large amounts of information about expected flow regimes through different small-scale rock structures. This analysis shows how combined experimental and numerical characterisation of rock samples can be used to derive equivalent flow properties from heterogeneous rocks.

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Characterizing flow behavior for gas injection: Relative permeability of CO₂‐brine and N₂‐water in heterogeneous rocks

Reynolds

Krevor

2015

Water Resources Research

119

144

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We provide a comprehensive experimental study of steady state, drainage relative permeability curves with CO 2 -brine and N 2 -deionized water, on a single Bentheimer sandstone core with a simple two-layer heterogeneity. We demonstrate that, if measured in the viscous limit, relative permeability is invariant with changing reservoir conditions, and is consistent with the continuum-scale multiphase flow theory for water wet systems. Furthermore, we show that under capillary limited conditions, the CO 2 -brine system is very sensitive to heterogeneity in capillary pressure, and by performing core floods under capillary limited conditions, we produce effective relative permeability curves that are flow rate and fluid parameter dependent. We suggest that the major uncertainty in past observations of CO 2 -brine relative permeability curves is due to the interaction of CO 2 flow with pore space heterogeneity under capillary limited conditions and is not due to the effects of changing reservoir conditions. We show that the appropriate conditions for measuring intrinsic or effective relative permeability curves can be selected simply by scaling the driving force for flow by a quantification of capillary heterogeneity. Measuring one or two effective curves on a core with capillary heterogeneity that is representative of the reservoir will be sufficient for reservoir simulation.

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Accurate determination of characteristic relative permeability curves

Cited by 64 publications

References 72 publications

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Characterizing flow behavior for gas injection: Relative permeability of CO₂‐brine and N₂‐water in heterogeneous rocks

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Accurate determination of characteristic relative permeability curves

Cited by 64 publications

References 72 publications

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

Capillary Heterogeneity Trapping and Crossflow in Layered Porous Media

Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Characterizing flow behavior for gas injection: Relative permeability of CO2‐brine and N2‐water in heterogeneous rocks

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Product

Resources

About

Characterizing flow behavior for gas injection: Relative permeability of CO₂‐brine and N₂‐water in heterogeneous rocks