Upscaling of CO2 injection into brine with capillary heterogeneity effects

Rabinovich, Avinoam; Itthisawatpan, Kasama; Durlofsky, Louis J.

doi:10.1016/j.petrol.2015.07.021

Cited by 55 publications

(34 citation statements)

References 35 publications

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“…In these systems, low flow potential gas plumes are significantly impacted by capillary pressure heterogeneity (Saadatpoor et al, 2010), which can result in equivalent relative permeabilities which are far from the viscous limit values (Li and Benson, 2015;Rabinovich et al, 2015). We use both Nitrogen -DI water and CO 2 -Brine fluid pairs, so that the impact of capillary pressure heterogeneity can be clearly demonstrated independently of variations caused by the choice of fluid pair.…”

Section: Characterisation Of Multiphase Flow Properties On Heterogenementioning

confidence: 99%

“…In upscaling procedures, the fine-scale flow functions are averaged at a larger scale, either analytically or numerically, to reduce computation cost whilst maintaining the underlying physical attributes of the fine-scale flow (Rabinovich et al, 2015). While most upscaling efforts focus on upscaling heterogeneous permeability distributions (Holden and Nielsen, 2000;Jackson et al, 2003) or relative permeability (Barker and Dupouy, 1999;Gasda and Celia, 2005), only recently have strong capillary pressure heterogeneity effects been incorporated (Rabinovich et al, 2015). When capillary pressure heterogeneity is incor-porated into a dynamic upscaling procedure (as opposed to using simpler capillary or viscous limit upscaling), the resulting equivalent relative permeability is both flow rate and heterogeneity dependent, i.e.…”

Section: Introductionmentioning

confidence: 99%

“…When capillary pressure heterogeneity is incor-porated into a dynamic upscaling procedure (as opposed to using simpler capillary or viscous limit upscaling), the resulting equivalent relative permeability is both flow rate and heterogeneity dependent, i.e. dependent on the capillary number (Virnovsky et al, 2004;Rabinovich et al, 2015;Odsaeter et al, 2015). Making use of such a modelling framework, however, requires the development of laboratory based characterisation protocols from which the properties of capillary heterogeneity, and their impacts on multiphase flow are initially derived.…”

Section: Introductionmentioning

confidence: 99%

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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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Section: Characterisation Of Multiphase Flow Properties On Heterogenementioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Jackson¹,

Agada²,

Reynolds³

et al. 2017

Preprint

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“…In the reservoir, there is significant natural capillary heterogeneity throughout the rocks. The impact of this heterogeneity can be represented using upscaled flow functions if the heterogeneity can be accurately characterized in the laboratory (Li & Benson, ; Rabinovich et al, ). However, this characterization, like the capillary end effect, requires a numerical history match of core‐flood observations (Jackson et al, ; Krause, ; Sigmund & McCaffery, ) and incurs similar uncertainty around the uniqueness of the inferred multiphase flow properties.…”

Section: Introductionmentioning

confidence: 99%

Imaging and Measurement of Pore‐Scale Interfacial Curvature to Determine Capillary Pressure Simultaneously With Relative Permeability

Lin

Bijeljic

Pini

et al. 2018

Water Resources Research

100

104

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There are a number of challenges associated with the determination of relative permeability and capillary pressure. It is difficult to measure both parameters simultaneously on the same sample using conventional methods. Instead, separate measurements are made on different samples, usually with different flooding protocols. Hence, it is not certain that the pore structure and displacement processes used to determine relative permeability are the same as those when capillary pressure was measured. Moreover, at present, we do not use pore‐scale information from high‐resolution imaging to inform multiphase flow properties directly. We introduce a method using pore‐scale imaging to determine capillary pressure from local interfacial curvature. This, in combination with pressure drop measurements, allows both relative permeabilities and capillary pressure to be determined during steady state coinjection of two phases through the core. A steady state waterflood experiment was performed in a Bentheimer sandstone, where decalin and brine were simultaneously injected through the core at increasing brine fractional flows from 0 to 1. The local saturation and the curvature of the oil‐brine interface were determined. Using the Young‐Laplace law, the curvature was related to a local capillary pressure. There was a detectable gradient in both saturation and capillary pressure along the flow direction. The relative permeability was determined from the experimentally measured pressure drop and average saturation obtained by imaging. An analytical correction to the brine relative permeability could be made using the capillary pressure gradient. The results for both relative permeability and capillary pressure are consistent with previous literature measurements on larger samples.

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“…[], Rabinovich et al . [], and the review by Hassan and Xi []. In these investigations, three properties are generally upscaled: permeability, k , relative permeability to phase j , k rj , and capillary pressure, P c .…”

Section: Introductionmentioning

confidence: 99%

Analytical approximations for effective relative permeability in the capillary limit

Rabinovich

Durlofsky

2016

Water Resour. Res.

Self Cite

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We present an analytical method for calculating two‐phase effective relative permeability, krjeff, where j designates phase (here CO2 and water), under steady state and capillary‐limit assumptions. These effective relative permeabilities may be applied in experimental settings and for upscaling in the context of numerical flow simulations, e.g., for CO2 storage. An exact solution for effective absolute permeability, keff, in two‐dimensional log‐normally distributed isotropic permeability (k) fields is the geometric mean. We show that this does not hold for krjeff since log normality is not maintained in the capillary‐limit phase permeability field ( Kj=k·krj) when capillary pressure, and thus the saturation field, is varied. Nevertheless, the geometric mean is still shown to be suitable for approximating krjeff when the variance of ln⁡k is low. For high‐variance cases, we apply a correction to the geometric average gas effective relative permeability using a Winsorized mean, which neglects large and small Kj values symmetrically. The analytical method is extended to anisotropically correlated log‐normal permeability fields using power law averaging. In these cases, the Winsorized mean treatment is applied to the gas curves for cases described by negative power law exponents (flow across incomplete layers). The accuracy of our analytical expressions for krjeff is demonstrated through extensive numerical tests, using low‐variance and high‐variance permeability realizations with a range of correlation structures. We also present integral expressions for geometric‐mean and power law average krjeff for the systems considered, which enable derivation of closed‐form series solutions for krjeff without generating permeability realizations.

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Upscaling of CO2 injection into brine with capillary heterogeneity effects

Cited by 55 publications

References 35 publications

Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Characterising Drainage Multiphase Flow in Heterogeneous Sandstones

Imaging and Measurement of Pore‐Scale Interfacial Curvature to Determine Capillary Pressure Simultaneously With Relative Permeability

Analytical approximations for effective relative permeability in the capillary limit

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