Experimental Coreflooding and Numerical Modeling of CO2 Injection With Gravity and Diffusion Effects

Moortgat, Joachim; Firoozabadi, Abbas; Liu, Zhidong; Espósito, Rogério Oliveira

doi:10.2118/135563-ms

Cited by 15 publications

(7 citation statements)

References 14 publications

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“…The reservoir fluid model was created from a PVT test proposed by Moortgat et al (2010), which is light and has 8% molar CO2, whose characteristics can be considered similar to those of the fluids extracted from the pre-salt layer.…”

Section: Methodsmentioning

confidence: 99%

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Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt

Silva

Hernandez²,

Barillas³

2023

RSD

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The hysteresis of relative permeability and capillary pressure need to be more widespread in academic studies, in order to understand how they can influence reservoirs with light oil and high pressure. These phenomena become extremely important to have a good prediction of oil production, considering that in many cases, the use of hysteresis in calculations can lead to a better prediction of oil recovery, allowing the exploration of certain fields. Thus, this study had as main objective the analysis of two hysteresis models (Killough and Larsen and Skauge) widely used in commercial software, in order to investigate the behavior of a light oil reservoir using a miscible WAG-CO2 process. Thus, to achieve this goal, a semi-synthetic reservoir, with characteristics similar to those found in the Brazilian pre-salt, was considered and was modeled using commercial software from CMG. Hysteresis reduces fluid permeability, which can generate two effects: increased local sweep efficiency of the oil and loss of injectivity. The former effect contributes to increased oil recovery, while injectivity loss can decrease oil sweep, reducing oil recovery. Furthermore, this work found that hysteresis can cause loss of gas and water injectivity, however this did not prevent hysteresis from increasing oil recovery compared to the case without hysteresis.

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Section: Methodsmentioning

confidence: 99%

“…The characteristic of the oil is: °API = 33. The differential release results that were published by Moortgat et al (2010) were used in creating the fitted fluid model using WINPROP.…”

Section: Methodsmentioning

confidence: 99%

Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt

Silva

Hernandez²,

Barillas³

2023

RSD

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“…A number of laboratory experiments have been performed indicating the importance of diffusion (Thiebot and Sakthikumar 1991;Morel et al 1993;Le Romancer and Fernandes 1994;Lenormand et al 1998;Hatiboglu and Babadagli 2004;Karimaie et al 2007;Torabi and Asghari 2009;Moortgat et al 2010). On the basis of the results of laboratory experiments and on the basis of fluid-flow dynamics, several additional papers investigating the effect of diffusion in fractured reservoirs have been published (Grogan and Pinczewski 1987;da Silva and Belery 1989;Coats 1989;Uleberg and Høier 2002;Alavian and Whitson 2009).…”

Section: Field Casementioning

confidence: 99%

The Role of Diffusion for Nonequilibrium Gas Injection Into a Fractured Reservoir

Yanze

Clemens

2012

SPE Reservoir Evaluation &Amp; Engineering

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The Schönkirchen Tief oil field is located in the Vienna basin in Austria. It is a pervasively fractured dolomite reservoir that has been produced for more than 50 years. The field is at the tail end of production, the wells are perforated close to the top of the reservoir, and water is injected downdip. Because of the location of the field close to one of the main gas pipelines in Austria, it is planned to convert the field into high-performance underground gas storage (UGS).The field is characterized by a highly permeable fracture system and a less-permeable matrix system. It is expected that some incremental oil can be recovered because of gas/oil gravity drainage from the matrix.In addition to gas/oil gravity drainage, diffusion will have an effect on the oil recovery. The injected gas is leaner than the equilibrium gas in the reservoir. Hence, gas components diffuse from the fracture system into the matrix and components of the oil diffuse toward the fracture system. This results in a modification of the properties of the oil affected by diffusion.This type of gas injection results in a zone of decreased oil viscosity for gases such as CO 2 and CH 4 at the interface of the gas and the oil in the matrix. This zone of lower oil viscosity increases the gas/oil gravity-drainage rates.The results show that the effect of diffusion can increase cumulative oil production up to 25% compared with a case neglecting the effect of diffusion. The effect of diffusion could be determined for various parameters such as permeability, porosity, fracture spacing, and matrix-block height. While for some of the parameters the effect of diffusion scales with the square root of time (e.g., permeability), for others an exponential relationship has been determined (fracture spacing).The results derived for the example reservoir can be used more generally to screen whether the effect of diffusion should be incorporated into reservoir studies concerning nonequilibrium-gas injection and to determine how large the error could be in the case where diffusion is neglected. Reservoir ProcessesOil recovery from pervasively fractured reservoirs is challenging because of the often large contrast in permeability of the fractures

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“…Under ambient temperature and pressure conditions in a typical aquifer, CO 2 dissolves into the aqueous phase (brine) and creates a dense interfacial layer The CO 2saturated brine in a saline aquifer is 0.1% to 1% denser than natively formed brine, depending on the pressure, temperature, and salinity. Gravitational instability or unstable stratification triggers the convection of fluids, which is commonly referred to as density-driven convection in the literature [5,6]. As the CO 2 dissolves into the underlying brine, the CO 2 -saturated brine becomes denser than the native brine, and the density difference causes instability and triggers convection.…”

Section: Introductionmentioning

confidence: 99%

Co-injection of CO2 and Nanoparticles Enhance Sequestration Potential in Subsurface Aquifers

Sijia¹,

Wang²,

Li³

et al. 2022

Preprint

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CO 2 storage in deep saline aquifers is a promising technique for carbon neutrality. Accelerating the dissolution rate of dissolution trapping is key to improving storage efficiency and providing long-term storage security. In this study, density-driven convection processes were conducted using magnetic resonance imaging (MRI) with two analog fluid pairs as equivalents of the CO 2 -brine fluid system. Superhydrophilic SiO 2 NPs with different mass fractions (0 wt%, 0.1 wt%, and 1 wt%) were added to the dense fluid to investigate the optimum mixing ratio. The basic fluid interface instability is identified. The addition of nanoparticles shortens the onset time of instability and increases the finger numbers in each axial section. It shows that dense fluid with NPs leads to more stable interface behavior. Furthermore, experimental results confirm that a reduction in surface tension between NPs and CO 2 would enhance fluid miscibility and the mass transfer during convection. This study can expand the perspective on accelerated dissolution rates and CCS security in the substance.

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Experimental Coreflooding and Numerical Modeling of CO2 Injection With Gravity and Diffusion Effects

Cited by 15 publications

References 14 publications

Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt

Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt

The Role of Diffusion for Nonequilibrium Gas Injection Into a Fractured Reservoir

Co-injection of CO2 and Nanoparticles Enhance Sequestration Potential in Subsurface Aquifers

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