Modeling rock-fluid interactions due to CO2 injection into sandstone and carbonate aquifer considering salt precipitation and chemical reactions

Ghafoori, Milad; Tabatabaei-Nejad, Seyyed Alireza; Khodapanah, Elnaz

doi:10.1016/j.jngse.2016.11.063

Cited by 16 publications

(11 citation statements)

References 20 publications

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“…This time scale separation of the progress of the two fronts has also been identified in previous studies, both experimentally and numerically (Giorgis et al., 2007; Nooraiepour et al., 2018; Peysson, 2012; Pruess & Mueller, 2009). These two main fronts, namely, a displacement front and a dry‐out front, are often identified in simplified models of salt precipitation in homogeneous porous media under a linear flow assumption, leading to the identification of three distinct zones (Figure 1) (Ghafoori et al., 2017; Nooraiepour et al., 2018).…”

Section: Simulation Results and Discussionmentioning

confidence: 99%

“…Other studies have reported the formation of a moving drying front that, behind the two‐phase flow displacement front, separates the medium into three distinct zones. These three zones are illustrated in Figure 1(Burton et al., 2008; Ghafoori et al., 2017; Nooraiepour et al., 2018). Conversely, homogeneous salt precipitation, or nonlocal precipitation, has also been reported during the injection of CO 2 when reaction kinetics are slow relative to advection rates (Jones & Detwiler, 2019; Kim et al., 2012; Roels et al., 2014).…”

Section: Introductionmentioning

confidence: 99%

“…The impact of salt precipitation on the permeability of geologic media is often studied using permeability‐porosity, k ‐ ϕ , relationships (Ghafoori et al., 2017; Ott et al., 2015; Roels, 2015; Tang et al., 2014). These k ‐ ϕ relationships aim at correlating overall reductions in porosity with reductions in permeability, thus ultimately capturing scCO 2 injectivity losses caused by salt precipitation.…”

Section: Introductionmentioning

confidence: 99%

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Permeability Impairment and Salt Precipitation Patterns During CO₂ Injection Into Single Natural Brine‐Filled Fractures

Lima

Schädle

Green

et al. 2020

Water Resources Research

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Formation dry‐out in fracture‐dominated geological reservoirs may alter the fracture space, impair rock absolute permeability, and cause a significant decrease in well injectivity. In this study, we numerically model the dry‐out processes occurring during supercritical CO2 (scCO2) injection into single brine‐filled fractures and evaluate the potential for salt precipitation under increasing effective normal stresses in the evaporative regime. We use an open‐source, parallel finite‐element framework to numerically model two‐phase flow through 2‐D fracture planes with aperture fields taken from naturally fractured granite cores at the Grimsel Test Site in Switzerland. Our results reveal a displacement front and a subsequent dry‐out front in all simulated scenarios, where higher effective stresses caused more flow channeling, higher rates of water evaporation, and larger volumes of salt precipitates. However, despite the larger salt volumes, the permeability impairment was lower at higher effective normal stresses. We conclude that the spatial distribution of the salt, precipitated in fractures with heterogeneous aperture fields, strongly affects the absolute permeability impairment caused by formation dry‐out. The numerical simulations assist in understanding the behavior of the injectivity in fractures and fracture networks during subsurface applications that involve scCO2 injection into brine.

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Section: Simulation Results and Discussionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Permeability Impairment and Salt Precipitation Patterns During CO₂ Injection Into Single Natural Brine‐Filled Fractures

Lima

Schädle

Green

et al. 2020

Water Resources Research

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“…Although the study is very comprehensive, the permeabilities studied were 100 and 10 mD; one can argue that those values are not really reflecting the mechanisms in low permeable range. In a simulation study, Ghafoori et al [34] examined CO 2 injection to carbonate and sandstone aquifers. They concluded that permeability changes do not influence equilibrium regions and the only effect that permeability has is on the injectivity.…”

Section: Introductionmentioning

confidence: 99%

CO2 Storage in Low Permeable Carbonate Reservoirs: Permeability and Interfacial Tension (IFT) Changes During CO2 Injection in an Iranian Carbonate Reservoir

Karaei

Honarvar

Azdarpour

et al. 2019

Period. Polytech. Chem. Eng.

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The lack of fundamental experimental studies on low permeable carbonate reservoirs for CO2 sequestration purposes is essential for further application of CO2 sequestration as a highly-anticipated CO2 mitigation method in deep saline aquifers, specifically those with low permeabilities. The core samples were taken from a carbonate reservoir in Iran and the brine composition was based on that of the same formation. The objective of this study is to investigate permeability alteration during CO2 sequestration in the aquifers of a low permeable Iranian carbonate reservoir. Various parameters have been investigated. The effects of different parameters such as injection pressure, confining pressure, and temperature on permeability alteration of the cores was investigated. Moreover, the interfacial tension (IFT) of CO2/brine was also determined at pressures and temperatures up to 7 MPa and 100 °C, respectively. The experimental results showed CO2 solubility and rock dissolution to be the governing mechanism when CO2 was injected into carbonate cores. The permeability measurements showed that permeability increases by increasing injection pressure and decreases by increasing confining pressure and temperature. The IFT measurement results showed that the IFT decreases significantly when there is an increase in pressure and temperature.

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“…Nowadays, settlement of contradiction between environmental protection and growing energy demand is the key to sustainable and high-level development in the future (Ghafoori, et al, 2017;Li, et al, 2017). Although great breakthroughs in green and new energy resources have been continuously achieved, traditional energy like petroleum still dominates the structure.…”

Section: Introductionmentioning

confidence: 99%

Thermo-Hydraulic Coupled Simulation of Immiscible Co2 Flooding

Zhao¹,

Guo²,

Feng³

2019

Appl. Ecol. Env. Res.

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As an efficient way to reduce CO2 in the atmosphere and to extract more hydrocarbons from reservoir, CO2 flooding is important to reduce environmental and ecological damage by traditional energy. Study on performance of CO2 in the reservoir and its impact on formation fluids is necessary to oil recovery and to further carbon capture and storage (CCS). In practical, CO2 is injected into reservoir at low temperature, and both field tests and predictions show that temperature of CO2 would be lower than that of reservoir while it reaches the target formation, especially for high injection rate. Therefore, further estimation should be conducted to predict how reservoir temperature and properties of fluids are changed during cold CO2 flooding. In this paper, a mathematical model for non-isothermal immiscible CO2 flooding is firstly established, then full thermo-hydraulic coupling of the model is simulated on COMSOL by introducing several temperature-dependent and pressure-dependent physical properties of CO2, oil and rock. The basic reservoir parameters of the model are obtained from one block of Daqing Oilfield, China. Furtherly, effect of CO2 injection temperature, of CO2 injection rate and of injector shut-in on reservoir performance is studied. Results show that injection of colder CO2 causes rapid reduction in reservoir temperature near the injector at the earlier stage. Effect of temperature change is timely shown on physical properties of fluids for full thermo-hydraulic coupling. Oil production rate, oil recovery and production gas-oil ratio all increase as injection temperature increases. Based on a practical situation, this study gives an insight into reservoir performance during cold CO2 flooding with a numerical method, and it can provide some support for study on temperature change in the reservoir.

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Modeling rock-fluid interactions due to CO2 injection into sandstone and carbonate aquifer considering salt precipitation and chemical reactions

Cited by 16 publications

References 20 publications

Permeability Impairment and Salt Precipitation Patterns During CO₂ Injection Into Single Natural Brine‐Filled Fractures

Permeability Impairment and Salt Precipitation Patterns During CO₂ Injection Into Single Natural Brine‐Filled Fractures

CO2 Storage in Low Permeable Carbonate Reservoirs: Permeability and Interfacial Tension (IFT) Changes During CO2 Injection in an Iranian Carbonate Reservoir

Thermo-Hydraulic Coupled Simulation of Immiscible Co2 Flooding

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Modeling rock-fluid interactions due to CO2 injection into sandstone and carbonate aquifer considering salt precipitation and chemical reactions

Cited by 16 publications

References 20 publications

Permeability Impairment and Salt Precipitation Patterns During CO2 Injection Into Single Natural Brine‐Filled Fractures

Permeability Impairment and Salt Precipitation Patterns During CO2 Injection Into Single Natural Brine‐Filled Fractures

CO2 Storage in Low Permeable Carbonate Reservoirs: Permeability and Interfacial Tension (IFT) Changes During CO2 Injection in an Iranian Carbonate Reservoir

Thermo-Hydraulic Coupled Simulation of Immiscible Co2 Flooding

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Product

Resources

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Permeability Impairment and Salt Precipitation Patterns During CO₂ Injection Into Single Natural Brine‐Filled Fractures

Permeability Impairment and Salt Precipitation Patterns During CO₂ Injection Into Single Natural Brine‐Filled Fractures