Investigating Uncertainties in Relative Permeability Measurements

Boukadi, F.; Bemani, A. S.; Babadagli, Tayfun

doi:10.1080/00908310490450638

Cited by 8 publications

(3 citation statements)

References 6 publications

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“…Three commonly used methods for measuring relative permeability data are unsteady-state, steady-state, and centrifuge. These approaches were discussed in terms of their advantages and limitations by Boukadi et al (2005), with authors acknowledging the presence of errors and uncertainties in the collected data in all methods. In the context of foam, foam quality scan and flow rate scan experiments are commonly employed to evaluate foam properties and determine the parameters of computational models (Zeng et al, 2016).…”

Section: Introductionmentioning

confidence: 99%

On the Identifiability of Relative Permeability and Foam Displacement Parameters in Porous Media Flow

Ribeiro,

Miranda,

Rocha

et al. 2024

Water Resources Research

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This study focuses on analyzing parameter identifiability in foam displacement models during two‐phase flow in porous media, with a particular emphasis on calibrating relative permeability and foam parameters. We employ the profile likelihood technique and Bayesian inference for identifiability analysis. Successful parameter estimation is demonstrated through steady‐state experiments for relative permeability and foam quality scan experiments when both types of experimental data are available and obtained from the same core sample. However, non‐identifiability issues arise when only foam quality scan data is accessible. Additionally, we investigated a standard practice that fits foam parameters using foam quality scan data obtained from one core sample and permeability values obtained from another core sample, but from the same reservoir. Our results show that this practice is ineffective in correctly estimating foam parameters, leading to misestimation of crucial foam model parameters. These findings underscore the importance of a mandatory relative permeability experiment on a representative core sample from the reservoir for accurate characterization of foam parameters. Without it, misestimation of foam model parameters hinders the proper understanding of foam effects on sweeping porous media.

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Section: Introductionmentioning

confidence: 99%

On the Identifiability of Relative Permeability and Foam Displacement Parameters in Porous Media Flow

Ribeiro,

Miranda,

Rocha

et al. 2024

Water Resources Research

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“…There are several studies in the literature addressed significant role of three-phase relative permeability data in numerical simulation of different enhanced oil recovery techniques, such as Water Alternate Gas injection (WAG) (Land, 1968;Christensen et al, 2001;Element et al, 2003;Spiteri and Juanes, 2006;, Cyclic Steam Stimulation (CSS) (Dietrich, 1981;Lake, 1989;Dria et al, 1993), gas injections (Muqeem et al, 1993;kalaydjian et al, 1996), in-situ combustion (Schneider and Owens, 1970), Surfactant flooding (Foulser et al, 1992), Steam Assisted Gravity Drainage (SAGD) process (Chalier et al, 1995), Gas Assisted Gravity Drainage (GAGD) process (Blunt et al, 1995), and CO2 geological sequestrations in depleted reservoirs (Koide et al, 1992). Inaccurate relative permeability data is blamed to be a major source of uncertainty in performance predictions with numerical simulators (Demond et al, 1996;Boukadi et al, 2005). In the past decades, numerous attempts have been made to reduce uncertainty with the input data used in the numerical simulators (Capen, 1976;Bu and Damsleth, 1996;Hastings et al, 2001;Caldwell and Heather, 2001).…”

Section: Introductionmentioning

confidence: 99%

Estimation of Three-Phase Relative Permeability Isoperms in Heavy Oil/Water/Carbon Dioxide and Heavy Oil/Water/Methane Systems

2013

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Three-phase relative permeability data is an Achilles' heel in the field performance prediction of the enhanced heavy oil recovery processes with numerical simulation. Minor inaccuracy could lead to erroneous predictions and, in turn, considerable revenue losses. A technique is proposed to utilize two-and three-phase displacement experiments in order to estimate relative permeability isoperms for a fluid system of heavy oil/water/gas. Three-phase flow zone is determined in a ternary diagram with residual oil and irreducible water saturations obtained from two-phase heavy oil/water displacements experiments. A developed fully implicit three-phase simulator mimics three-phase displacement experiments in the form of gas (carbon dioxide and methane) injection into a consolidated Berea core saturated with heavy oil (1174cP at 28°C) and water. Threephase relative permeability data corresponds to a saturation path, drawn across the three-phase flow zone, is tuned to match simulated pressure drop, oil and water production with three-phase displacement experiment. Results have indicated, due to high residual oil saturation, a small three-phase flow zone can exist in presence of heavy oils. Although different curvatures have been obtained with relative permeability isoperms of oil, water, and gas phases; however, repeating experinemts with different gases (methane and carbon dioxide) indicates that relative permeability isoperms does not change siginificantly in presence of different gases. Comparison of the proposed procedure with the unsteady state technique indicates that unsteady state technique fails to provide reliable relative permeability data for numerical simulation purposes since it calculates three-phase relative permeability data at saturations out of the three-phase flow zone. In addition, in the case of water, unsteady state technique gives relative permeability values for a short range of water saturations. Proposed technique takes advantage of practicability of displacement experiments to estimate three-phase relative permeabilities it and, also, eliminates uncertainties with unsteady state method such as inaccurate derivative calculations. Although proposed method indirectly estimates three-phase relative permeabilities; sensitivity analysis shows a good margin of confidence with the relative permeability isoperms.

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“…For the recovery methods involving the simultaneous flow of three fluids, a three-phase relative permeability would be required to simulate the process. Inaccuracies in this important flow function have been identified as one of the major sources of uncertainty in reservoir performance prediction [16].…”

Section: Introductionmentioning

confidence: 99%

An Improved Approach to Estimate Three-Phase Relative Permeability Functions for Heavy-Oil Displacement Involving Instability and Compositional Effects

et al. 2017

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Simultaneous three-phase flow of gas, oil and water is a common phenomenon in enhanced oil recovery techniques such as water-alternating-gas (WAG) injection. Reliable reservoir simulations are required to predict the performance of these injections before field application. However, heavy oil displacement by gas or water can lead to viscous fingering due to the unfavorable mobility ratio between heavy oil and the displacing fluid. In addition, the injection of partially dissolvable gases such as CO 2 can result in compositional effects, which can bring about a significant reduction of oil viscosity and hence can cause variations of the mobility ratio. Estimations of three-phase relative permeability under such conditions are extremely complex, and using conventional techniques for the estimation can lead to erroneous results. We used the results of four coreflood experiments, carried out on a core, to estimate two-phase and three-phase relative permeability. A new history matching methodology for laboratory experiments was used that takes into account the instability and the compositional effects in the estimation processes. The results demonstrate that a simultaneous CO 2 and water injection (CO 2 -simultaneous water and gas (SWAG)) can be adequately matched using the relative permeabilities of a secondary gas/liquid and a tertiary oil/water. In heavy oil WAG injection, the injected water follows the CO 2 path due its lower resistance as a result of the CO 2 dissolution in the oil and the resultant reduction of the oil viscosity. This is contrary to WAG injection in conventional oils, where gas and water open up separate saturations paths. It is also important to include capillary pressure (Pc), even in high permeable porous media, as we observed that the inclusion of capillary pressure dampened the propagation of the viscous fingers and hence helped the front to become stabilized, leading to a more realistic simulated sweep efficiency.

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Investigating Uncertainties in Relative Permeability Measurements

Cited by 8 publications

References 6 publications

On the Identifiability of Relative Permeability and Foam Displacement Parameters in Porous Media Flow

On the Identifiability of Relative Permeability and Foam Displacement Parameters in Porous Media Flow

Estimation of Three-Phase Relative Permeability Isoperms in Heavy Oil/Water/Carbon Dioxide and Heavy Oil/Water/Methane Systems

An Improved Approach to Estimate Three-Phase Relative Permeability Functions for Heavy-Oil Displacement Involving Instability and Compositional Effects

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