A Versatile Representation of Upscaled Relative Permeability for Field Applications

Lomeland, Frode; Hasanov, Bashir; Ebeltoft, Einar; Berge, Marianne

doi:10.2118/154487-ms

Cited by 22 publications

(23 citation statements)

References 17 publications

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“…Once field data are available at a given site, history matching and model calibration can reduce model uncertainty and increase the predictive power of site specific models. In such efforts, core-scale relative permeability models are up-scaled to field-scale relative permeability models (Lomeland et al 2012), but non-unique relationships between intrinsic and relative permeability models may result from such model calibration (Mishra et al 2014). In addition, the 2D homogeneous model used in this work represents average intrinsic permeability of the reservoir, but heterogeneity in intrinsic permeability may attenuate the effects of relative permeability uncertainty reducing the variance of the CO 2 storage capacity.…”

Section: Discussionmentioning

confidence: 99%

Investigation of uncertainty in CO2 reservoir models: A sensitivity analysis of relative permeability parameter values

Yoshida

Levine

Stauffer

2016

International Journal of Greenhouse Gas Control

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Numerical reservoir models of CO 2 injection in saline formations rely on parameterization of laboratorymeasured pore-scale processes. We performed a parameter sensitivity study and Monte Carlo simulations to determine the normalized change in total CO 2 injected using the finite element heat and mass-transfer code (FEHM) numerical reservoir simulator. Experimentally measured relative permeability parameter values were used to generate distribution functions for parameter sampling. The parameter sensitivity study analyzed five different levels for each of the relative permeability model parameters. All but one of the parameters changed the CO 2 injectivity by <10%, less than the geostatistical uncertainty that applies to all large subsurface systems due to natural geophysical variability and inherently small sample sizes. The exception was the end-point CO 2 relative permeability, 2 , the maximum attainable effective CO 2 permeability during CO 2 invasion, which changed CO 2 injectivity by as much as 80%. Similarly, Monte Carlo simulation using 1000 realizations of relative permeability parameters showed no relationship between CO 2 injectivity and any of the parameters but 2 , which had a very strong (R 2 =0.9685) power law relationship with total CO 2 injected. Model sensitivity to 2 points to the importance of accurate core flood and wettability measurements.

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Section: Discussionmentioning

confidence: 99%

Investigation of uncertainty in CO2 reservoir models: A sensitivity analysis of relative permeability parameter values

Yoshida

Levine

Stauffer

2016

International Journal of Greenhouse Gas Control

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“…The permeability outside the aquifer is 0.0001 md. The relative permeabilities are modeled using Corey‐type relations [ Lomeland et al ., ] as

k_{r w} = S_{n}^{L_{w}} / (S_{n}^{L_{w}} + E_{w} {(1 - S_{n})}^{T_{w}}), k_{r g} = {(1 - S_{n})}^{L_{g}} / ({(1 - S_{n})}^{L_{g}} + E_{g} S_{n}^{T_{g}})

, where the normalized water saturation is

S_{n} = (S_{w} - S_{w l}) / (1 - S_{w l} - S_{g l})

. We choose the irreducible water saturation S wl = 0.001 and the residual gas saturation S gl = 0.…”

Section: Representative Numerical Simulationsmentioning

confidence: 99%

Coupled multiphase flow and poromechanics: A computational model of pore pressure effects on fault slip and earthquake triggering

2014

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The coupling between subsurface flow and geomechanical deformation is critical in the assessment of the environmental impacts of groundwater use, underground liquid waste disposal, geologic storage of carbon dioxide, and exploitation of shale gas reserves. In particular, seismicity induced by fluid injection and withdrawal has emerged as a central element of the scientific discussion around subsurface technologies that tap into water and energy resources. Here we present a new computational approach to model coupled multiphase flow and geomechanics of faulted reservoirs. We represent faults as surfaces embedded in a three-dimensional medium by using zero-thickness interface elements to accurately model fault slip under dynamically evolving fluid pressure and fault strength. We incorporate the effect of fluid pressures from multiphase flow in the mechanical stability of faults and employ a rigorous formulation of nonlinear multiphase geomechanics that is capable of handling strong capillary effects. We develop a numerical simulation tool by coupling a multiphase flow simulator with a mechanics simulator, using the unconditionally stable fixed-stress scheme for the sequential solution of two-way coupling between flow and geomechanics. We validate our modeling approach using several synthetic, but realistic, test cases that illustrate the onset and evolution of earthquakes from fluid injection and withdrawal.

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“…The history matching method of obtaining unsteady-state relative permeability data has become a more popular method to obtain local values from measurements of overall pressure drop, effluent versus time, and, in some cases, in-situ saturation. The method presumes a relative permeability model (such as Corey model [39] and the LET model [40]) with prior fitting parameters and a capillary pressure curve (Leverett J function [41]). Using the experimental boundary and initial conditions, the coupled Darcy Buckingham equation and continuity equation are numerically solved.…”

Section: Introductionmentioning

confidence: 99%

A new unsteady-state method of determining two-phase relative permeability illustrated by CO2-brine primary drainage in berea sandstone

Chen

DiCarlo

2016

Advances in Water Resources

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This study presents a new unsteady-state method for measuring two-phase relative permeability by obtaining local values of the three key parameters (saturation, pressure drop, and phase flux) versus time during a displacement. These three parameters can be substituted to two-phase Darcy Buckingham Equation to directly determine relative permeability. To obtain the first two, we use a medical X-ray Computed Tomography (CT) scanner to monitor saturation in time and space, and six differential pressure transducers to measure the overall pressure drop and the pressure drops of five individual sections (divided by four pressure taps on the core) continuously. At each scanning time, the local phase flux is obtained by spatially integrating the saturation profile and converting this to the flux using a fractional flow framework. One advantage of this local method over most previous methods is that the capillary end effect is experimentally avoided; this improvement is crucial for experiments using low viscosity fluids such as supercritical and gas phases. To illustrate the new method, we conduct five CO 2-brine primary drainage experiments in a 60.8 cm long and 116 mD Berea sandstone core at 20 °C and 1500 psi. In return, we obtain hundreds of unsteady-state CO 2 and brine relative permeability data points that are consistent with steady-state relative permeability data from the same experiments. Due to the large amount of relative permeability data

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A Versatile Representation of Upscaled Relative Permeability for Field Applications

Cited by 22 publications

References 17 publications

Investigation of uncertainty in CO2 reservoir models: A sensitivity analysis of relative permeability parameter values

Investigation of uncertainty in CO2 reservoir models: A sensitivity analysis of relative permeability parameter values

Coupled multiphase flow and poromechanics: A computational model of pore pressure effects on fault slip and earthquake triggering

A new unsteady-state method of determining two-phase relative permeability illustrated by CO2-brine primary drainage in berea sandstone

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