Experimental Investigation of Three-Phase Relative Permeability under Simultaneous Water and Gas (SWAG) Injection

Moghadasi, Leili; Bartošek, Martin; Renna, D.; Maddinelli, G.; Scagliotti, S.

doi:10.3997/2214-4609.201900078

Cited by 4 publications

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“…Experimental Setup and Conditions. Figure 1 depicts a sketch of the experimental setup, a detailed description of our experimental setup is being illustrated by Moghadasi et al (2016Moghadasi et al ( , 2019. The experimental setup consists of a hassler type core holder placed vertically in a saturation monitoring apparatus.…”

Section: Methodsmentioning

confidence: 99%

“…It is 11.6 cm long and is placed inside a rubber sleeve (inner diameter of 5.08 cm) to pack the unconsolidated sandstone. A confining pressure of 90 bar is applied to stabilize the packing and prevent flow near the edges (Moghadasi et al 2019). The fluids used in the experiments are a mixture of (i) distilled water and (ii) different salts (e.g.…”

Section: Methodsmentioning

confidence: 99%

“…A detailed description of the methodology employed is presented in Moghadasi al. (2016Moghadasi al. ( , 2019.…”

Section: Two-phase and Three-phase Experimental Procedurementioning

confidence: 99%

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Combining Two- and Three-Phase Coreflooding Experiments for Reservoir Simulation Under WAG Practices

Moghadasi

Ranaee

Renna

et al. 2020

Day 3 Wed, January 15, 2020

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Enhanced oil recovery (EOR) processes may often involve simultaneous flow of two or three immiscible fluids inside the reservoir. A precise evaluation of relative permeabilities is critical to quantify multi-phase flow dynamics, assisting improved management and development of oil- and gas- bearing formations. This study illustrates the results of laboratory-scale investigations of multiphase flow on a sandstone reservoir core sample to evaluate relative permeabilities under two- and three-phase (i.e., water, oil, and gas) conditions. We use the ensuing information to simulate WAG injection at reservoir scale. The experiments are conducted at high temperature, consistent with reservoir conditions, to obtain two- (oil/water and oil/gas) and three-phase (oil/water/gas) relative permeabilities through Steady-State (SS) technique. Our laboratory workflow allows for an improved investigation by combining coreflooding experiments with in-situ X-Ray evaluation of local saturation distribution. The latter technique permits to asses slice-averaged phase saturation along the rock core, enabling to compute saturation profiles and average saturations while flooding, thus yielding significant advantages over traditional methodologies based on mass balance. Three-phase steady state (SS) experiments are performed by following diverse saturation paths, and the complete experimental dataset is provided to (a) assess the occurrence of local three-phase saturation conditions and (b) possibly investigate hysteretic effects of relative permeabilities. We evaluate three-phase relative permeabilities across the entire three-phase saturation region by leveraging a Sigmoid-based model (Ranaee et al., 2015). The resulting set of experimental two- and three-phase coreflooding results constitute a unique dataset which is then employed for reservoir simulation studies mimicking WAG injection and results are discussed in comparison with reservoir production under a waterflooding scenario.

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Section: Methodsmentioning

confidence: 99%

Section: Methodsmentioning

confidence: 99%

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Combining Two- and Three-Phase Coreflooding Experiments for Reservoir Simulation Under WAG Practices

Moghadasi

Ranaee

Renna

et al. 2020

Day 3 Wed, January 15, 2020

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“…We perform our experiments on a Portland limestone core sample. A confining pressure of 90 bar is applied to stabilize the packing and prevent flow near the edges (see Moghadasi et al, 2019 for additional details). Table 1 lists some key attributes of the core samples.…”

Section: Experimental Setup and Conditionsmentioning

confidence: 99%

Implementation of Three-Phase Black-Oil Reservoir Models Assisted by Micro-Scale Analyses

et al. 2020

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Objective/Scopes: We aim at developing a viable workflow for the characterization of reservoir responses under Water Alternating Gas (WAG) conditions for enhanced oil recovery. We do so through a numerical Monte Carlo (MC) framework and by relying on (i) a classical approach, which is grounded on employing results from laboratory-scale core-flooding experiments or (ii) an approach based on relative permeability curves inferred from pore-scale numerical simulations. In these settings we investigate (i) the way uncertainties associated with the parameters of a reservoir model estimated through these approaches propagate to target modeling goals and (ii) assess (through Global Sensitivity Analyses) the relative importance of the uncertain quantities controlling the reservoir behavior via given model outcomes. Methods/Procedures: We consider uncertainty in (a) porosity and absolute permeability as well as (b) parameters of relative permeability models. Three scenarios are assessed, accounting for spatial distribution of porosity and absolute permeability with differing degrees of complexity and corresponding to (i) homogeneous; (ii) randomly heterogeneous; and (iii) well-connected randomly heterogeneous fields. Spatial realizations of the heterogeneous fields are generated considering Gaussian random fields with a Gaussian kernel variance driving the degree of spatial correlation. The two modeling approaches considered take advantage of two-phase relative permeability curves, which are interpreted via commonly used models with uncertain parameters. Three-phase relative permeabilities are then characterized through a previously developed and tested sigmoid-based oil relative permeability model by taking into account hysteretic behavior of gas relative permeability. All field-scale simulations are performed on a simple reservoir model and are set within the MRST suite. Results/Conclusions: In the case of a homogeneous reservoir, we note that reservoir simulation responses are strongly sensitive to the degree of convexity of the two-phase relative permeability curves. In the case of heterogeneous reservoir settings, results are almost similarly sensitive to porosity, characteristics of the Novel/Additive Information: Characterization of reservoir model attributes relying on pore-scale simulation approaches in the presence of uncertainty can provide a robust term of comparison which can be integrated within a classical reservoir simulation approach relying on relative permeability data stemming from core-flooding experiments. Our results document that uncertainties in the evaluation of (i) reservoir model petrophysical attributes (porosity/permeability) and (ii) relative permeability model parameters can differently influence field-scale simulation outputs, depending on the degree of spatial heterogeneity of the reservoir.

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Steady-State Multi-Phase Relative Permeability Under Simultaneous Water and Gas Injection: Application on Different Rock Types

Moghadasi

Renna

Bartošek

et al. 2019

Day 1 Tue, September 17, 2019

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Quantification of multi-phase flow processes taking place in natural porous and fractured rocks has a remarkable relevance to economically sustainable management and viable development of oil- and gas-bearing geologic formations. Simultaneous flow of two- and three- fluid phases in porous media is typically based on a continuum scale description which imbues relative permeabilities as key system parameters to be estimated and linked to fluid saturations. Estimates of relative permeabilities are then employed to support better the quantification of productivity, injectivity, and ultimate recovery from reservoirs. In this work, we report the results of laboratory-scale three-phase relative permeabilities on diverse core samples. We also investigate the saturation history dependency (i.e. hysteresis) of three-phase relative permeability during under simultaneous water and gas injection. Three-phase relative permeability data are obtained at different condition by the way of a Steady-State (SS) technique. We use direct X-Ray technique to assess the spatial and temporal dynamics of in-situ saturations. Dual X-Ray energies are employed to assess the SS three-phase saturations. The use of in-situ X-Ray scanning technology enables us to accurately measure fluid displacement during the core-flooding test. The SS three-phase experiments are condcuted by following various saturation paths including CDI, DDI and IDI. The C, D and I letters represent as Constant, Increasing and Decreasing (i.e., CDI saturation variation abbreviates Constant water, Decreasing oil and Increasing Gas). We observe in all the of the tests, water relative permeabilities display an approximately linear dependence on the logarithm of its own saturation and show no dependency upon saturation history. Three-phase oil relative permeability appears to be varied with all saturations and be dependent on all saturations phases. Gas three-phase relative permeability was affected more by saturation history than other phases. However in the test where the gas fractional flow was increased, the dependency of gas relative permeability on gas saturation was observed. As only a limited quantity of complete three-phase data are available, this study stands as a reliable reference for further model development and testing.

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Experimental Investigation of Three-Phase Relative Permeability under Simultaneous Water and Gas (SWAG) Injection

Cited by 4 publications

References 0 publications

Combining Two- and Three-Phase Coreflooding Experiments for Reservoir Simulation Under WAG Practices

Combining Two- and Three-Phase Coreflooding Experiments for Reservoir Simulation Under WAG Practices

Implementation of Three-Phase Black-Oil Reservoir Models Assisted by Micro-Scale Analyses

Steady-State Multi-Phase Relative Permeability Under Simultaneous Water and Gas Injection: Application on Different Rock Types

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