Laboratory investigation of oil viscosity effect during carbonated water injection: Comparison of secondary and tertiary recovery

Afra, Mohammad Javad Shokri; Horeh, Mohsen Bahaloo; Rostami, Behzad; Norouzi, Hamid Reza

doi:10.1002/cjce.23097

Cited by 11 publications

(5 citation statements)

References 28 publications

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“…As an example, in the case of the United States the CO

_{2}

storage capacity for saline aquifers is estimated as 12,000 Gt CO

_{2}

(Celia, ) while the estimation for depleted oil reservoirs is about 20 Gt CO

_{2}

(Godec et al, ). So deep saline aquifers are the primary long‐term options for carbon problem mitigation, while in the near‐term CO

_{2}

‐enhanced oil recovery (EOR) is increasingly being recognized as a commercial alternative to storage only operations (Balashov et al, ; Koytsoumpa et al, ; Kolster et al, ; Orr Jr, ; Shokri et al, ; Tapia et al, ).…”

Section: Introductionmentioning

confidence: 99%

Signature of Geochemistry on Density‐Driven CO Mixing in Sandstone Aquifers

Erfani

Babaei

Niasar

2020

Water Resources Research

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Density‐driven mixing resulting from CO 2 injection into aquifers leads to the CO 2 entrapment mechanism of solubility trapping. Crucially, the coupled flow‐geochemistry and effects of geochemistry on density‐driven mixing process for “sandstone rocks” have not been adequately addressed. Often, there are conflicting remarks in the literature as to whether geochemistry promotes or undermines dissolution‐driven convection in sandstone aquifers. Against this backdrop, we simulate density‐driven mixing in sandstone aquifers by developing a 2‐D modified stream function formulation for multicomponent reactive convective‐diffusive CO 2 mixing. Two different cases corresponding to laboratory and field scales are studied to investigate the effect of rock‐fluid interaction on density‐driven mixing and the role of mineralization in carbon storage over the project life time. A complex sandstone mineralogical assemblage is considered, and solid‐phase reactions are assumed to be kinetic to study the length‐ and time‐scale dependency of the geochemistry effects. The study revealed nonuniform impact of rock‐fluid and fluid‐fluid interaction in early‐ and late‐time stages of the process. The results show that for moderate Rayleigh (Ra) numbers, rock‐fluid interactions adversely affect solubility trapping while improving the total carbon captured through mineral trapping. Simulation results in the range of 1,500 < Ra < 55,000 in the field‐scale model showed more pronounced impact of geochemistry for higher Ra numbers, as geochemistry stimulates the convective instabilities and improves the total sequestered carbon. This study gives new insights into the effect of rock‐fluid interactions on density‐driven mixing and solubility trapping in sandstone aquifers to improve estimation of the carbon storage capacity in deep saline aquifers.

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“…As an example, in the case of the United States the CO

_{2}

storage capacity for saline aquifers is estimated as 12,000 Gt CO

_{2}

(Celia, ) while the estimation for depleted oil reservoirs is about 20 Gt CO

_{2}

(Godec et al, ). So deep saline aquifers are the primary long‐term options for carbon problem mitigation, while in the near‐term CO

_{2}

Section: Introductionmentioning

confidence: 99%

Signature of Geochemistry on Density‐Driven CO Mixing in Sandstone Aquifers

Erfani

Babaei

Niasar

2020

Water Resources Research

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“…Our achievements are also confirmed by the photographic images that are shown in Figure , which visualizes the elongation of the oil drop following the pendant drop method with the use of the nanofluids of FAU–0.09CTAB. It is worth mentioning here that the IFT measurements cannot be achieved with values less than 3mN/m due to the limitations associated with the pendant drop method at which the drop shape is no longer Laplacian …”

Section: Results and Discussionmentioning

confidence: 99%

“…It is worth mentioning here that the IFT measurements cannot be achieved with values less than 3mN/m due to the limitations associated with the pendant drop method at which the drop shape is no longer Laplacian. 45 The concentration of surfactant molecules grafted on FAU nanoparticles strongly influences the dynamic IFT reduction performance, as shown in Figure 9. It is expected that grafting greater amounts of CTAB on FAU nanoparticles, as confirmed by the TGA tests, might lead to enhancing the reduction in the IFT.…”

Section: Dynamic Light Scattering (Dls)mentioning

confidence: 99%

Influence of CTAB-Grafted Faujasite Nanoparticles on the Dynamic Interfacial Tension of Oil/Water Systems

et al. 2022

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In this study, the dynamic IFT and dilational rheological behavior of fluids/nanofluids generated from cetyltrimethylammonium bromide (CTAB)-grafted faujasite (FAU)-based nanoparticles were investigated in toluene–fluid/nanofluid interfaces under various conditions. To generate each nanofluid, FAU nanoparticles were initially synthesized under ambient conditions and then grafted with various quantities of CTAB surfactants. Afterward, the surface properties (i.e., morphology, surface area, functionality, and stability) of the synthesized nanoparticles before and after grafting with a low concentration of CTAB molecules were investigated by an array of characterization methods (XRD, HRTEM, BET surface area, ζ-potential, and DLS). The results showed that our generated FAU-based nanofluids outperformed the nongrafted FAU and physically mixed CTAB with FAU-based nanofluids in terms of IFT reduction. Our experimental IFT data were fitted with a general diffusion model that allowed us to determine the oil–water (o/w) emulsification mechanism due to the presence of CTAB-grafted nanoparticles. Based on our investigation, we emphasized that the IFT reduction was limited with the loading of a substantial amount of surfactant molecules, indicating that bulky nanoparticles are adsorbed slowly on the o/w interface. On the other hand, increasing the salinity level by introducing an additional amount of NaCl led to enhancing the levels of IFT reduction since the dissociated ions forced more surfactant molecules to migrate toward the o/w interface. A considerable viscoelasticity enhancement was remarked in the presence of our CTAB-grafted nanofluids, indicating that the presence of FAU nanoparticles in the core of the grafted nanoparticles robustly allowed the adsorption of higher amounts of CTAB molecules at the interface with less aggregation. The findings of this study shed light on the applications of nanofluids generated from grafted nanoparticles at the o/w systems, which can significantly increase the oil production at the end of water flooding with more efficient emulsification with surfactant concentration lower than the critical micelle concentration (CMC).

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“…Along with fluid-rock interactions, fluid-fluid interactions have been noticed during carbonated waterflooding in the microfluidic model. Fluid-fluid interactions include: (a) promoting oil swelling, (b) oil viscosity reduction, , (c) lowering oil-brine interfacial tension (IFT), (d) micro dispersion generation, ,, and (e) exsolution of CO 2 . However, compared to intensive investigation of fluid-rock interactions, the contribution of fluid-fluid interactions to multiphase flow has not been adequately addressed.…”

Section: Introductionmentioning

confidence: 99%

Fluid–Fluid Interfacial Effects in Multiphase Flow during Carbonated Waterflooding in Sandstone: Application of X-ray Microcomputed Tomography and Molecular Dynamics

Chen

Sari

et al. 2021

ACS Appl. Mater. Interfaces

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Fluid-fluid interfacial reactions in porous materials are pertinent to many engineering applications such as fuel cells, catalyst design, subsurface energy recovery (enhanced oil recovery), and CO2 storage. They have been identified to control physicochemical properties such as interfacial rheology, multiphase flow, and reaction kinetics. In recent years, engineered waterflooding has been identified as an effective way to increase hydrocarbon recovery and solid-fluid interaction has been assessed as the key mechanism. However, in this study, we demonstrated that in the absence of solid-fluid interactions (in strong hydrophilic porous media), fluid-fluid interfacial reactions can significantly affect multiphase flow and thus lead to an increased hydrocarbon recovery during engineered carbonated waterflooding. We designed a microwaterflooding system to evaluate the interfacial reactions during two phase flow with engineered carbonated waters. Given that salinity controls the amount of dissolved CO2, we injected carbonated high salinity water and carbonated low salinity water to achieve different fluid-fluid reactions. We injected the carbonated water in a sandstone with 99.5% quartz under X-ray microcomputed tomography (μCT) scanning at a resolution of 3.43 μm per pixel. Image processing shows that carbonated low salinity waterflooding can recover 8% more oil than carbonated high salinity waterflooding, while the quartz-rich sandstone remains strongly hydrophilic in both samples. A gradual CT intensity distribution indicates an interfacial phase generation between carbonated brine and crude oil during carbonated waterflooding. Therefore, we attributed the additional hydrocarbon recoveries to the fluid-fluid interfacial reactions. To understand the effects of fluid-fluid reactions on interfacial properties, we performed molecular dynamics simulations to investigate the chemical species distribution at the interface, interfacial tension (IFT) changes, and CO2 diffusion. The MD simulation results revealed a layered structure of the interface, a lower CO2 diffusion coefficient in carbonated high salinity water, a lower IFT in carbonated low salinity water, a swelling hydrocarbon phase in carbonated low salinity water, and more CO2 accumulated at the interface between the hydrocarbon phase and carbonated low salinity water. This work provides a general and fundamental understanding of the influence of fluid-fluid interactions on the interfacial properties between carbonated water and the hydrocarbon interface.

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Laboratory investigation of oil viscosity effect during carbonated water injection: Comparison of secondary and tertiary recovery

Cited by 11 publications

References 28 publications

Signature of Geochemistry on Density‐Driven CO Mixing in Sandstone Aquifers

Signature of Geochemistry on Density‐Driven CO Mixing in Sandstone Aquifers

Influence of CTAB-Grafted Faujasite Nanoparticles on the Dynamic Interfacial Tension of Oil/Water Systems

Fluid–Fluid Interfacial Effects in Multiphase Flow during Carbonated Waterflooding in Sandstone: Application of X-ray Microcomputed Tomography and Molecular Dynamics

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