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1. Asphaltene Precipitation and Deposition under Miscible and Immiscible Carbon Dioxide Gas Injection in Nanoshale Pore Structure

   https://doi.org/10.2118/210592-PA  

   Elturki, Mukhtar; Imqam, Abdulmohsin (June 2022, SPE Journal)

   Summary Asphaltene precipitation and deposition is considered one of the prevailing issues during carbon dioxide (CO2) gas injection in gas enhanced oil recovery techniques, which leads to pore plugging, oil recovery reduction, and damaged surface and subsurface equipment. This research provides a comprehensive investigation of the effect of immiscible and miscible CO2 gas injection in nanopore shale structures on asphaltene instability in crude oil. A slimtube was used to determine the minimum miscibility pressure (MMP) of the CO2. This step is important to ensure that the immiscible and miscible conditions will be achieved during the filtration experiments. For the filtration experiments, nanocomposite filter paper membranes were used to mimic the unconventional shale pore structure, and a specially designed filtration apparatus was used to accommodate the filter paper membranes. The uniform distribution (i.e., same pore size filters) was used to illustrate the influence of the ideal shale reservoir structure and to provide an idea on how asphaltene will deposit when utilizing the heterogeneous distribution (i.e., various pore size filters) that depicts the real shale structure. The factors investigated include immiscible and miscible CO2 injection pressures, temperature, CO2 soaking time, and pore size structure heterogeneity. Visualization tests were undertaken after the filtration experiments to provide a clear picture of the asphaltene precipitation and deposition process over time. The results showed an increase in asphaltene weight precent in all experiments of the filtration tests. The severity of asphaltene aggregations was observed at a higher rate under miscible CO2 injection. It was observed that the miscible conditions have a higher impact on asphaltene instability compared to immiscible conditions. The results revealed that the asphaltene deposition was almost equal across all the paper membranes for each pressure used when using a uniform distribution. Higher asphaltene weight percent were determined on smaller pore structures of the membranes when using heterogeneous distribution. Soaking time results revealed that increasing the soaking time resulted in an increase in asphaltene weight precent, especially for 60 and 120 minutes. Visualization tests showed that after 1 hour, the asphaltene clusters started to precipitate and could be seen in the uppermost section of the test tubes and were fully deposited after 12 hours with less clusters found in the supernatant. Also, smaller pore size of filter membranes showed higher asphaltene weight percent after the visualization test. Chromatography analysis provided further evaluation on how asphaltene was reduced though the filtration experiments. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes showed the severity of pore plugging in the structure of the membranes. This research highlights the impact of CO2 injection on asphaltene instability in crude oil in nanopore structures under immiscible and miscible conditions. The findings in this research can be used for further research of asphaltene deposition under gas injection and to scale up the results for better understanding of the main factors that may influence asphaltene aggregation in real shale unconventional reservoirs. 

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2. Experimental Measurements and Molecular Simulation of Carbon Dioxide Adsorption on Carbon Surface

   https://doi.org/10.2118/210264-MS  

   Gomaa, Ibrahim; Guerrero, Javier; Heidari, Zoya; Espinoza, D. Nicolas (September 2022, 2022 SPE Annual Technical Conference and Exhibition)

   Abstract Geological storage of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions of CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally investigate the effect of pressure and temperature on the CO2 adsorption capacity of activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo molecular modeling, and (iii) quantify the correlation between the adsorption isotherms of activated carbon-CO2 system and the actual carbon dioxide adsorption on shale-gas rock at different temperatures and geochemical conditions. Activated carbon is used as a proxy for kerogen. The objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage into shale-gas formations. We performed experimental measurements and Grand Canonical Monte Carlo (GCMC) simulations of CO2 adsorption onto activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas. Subsequently, we performed a series of GCMC simulations to calculate CO2 adsorption capacity on activated carbon to validate the experimental results. The simulated activated carbon structure consists of graphite sheets with a distance between the sheets equal to the average actual pore size of the activated carbon sample. Adsorption isotherms were calculated and modeled for each temperature value at various pressures. The adsorption of CO2 on activated carbon is favorable from the energy and kinetic point of view. This is due to the presence of a wide micro to meso pore sizes that can accommodate a large amount of CO2 particles. The results of the experimental work show that excess adsorption results for gas mixtures lie in between the results for pure components. The simulation results agree with the experimental measurements. The strength of CO2 adsorption depends on both surface chemistry and pore size of activated carbon. Once strong adsorption sites within nanoscale network are established, gas adsorption even at very low pressure is governed by pore width rather than chemical composition. The outcomes of this paper provides new insights about the parameters affecting CO2 adsorption and storage in shale-gas reservoirs, which is critical for developing standalone representative models for CO2 adsorption on pure organic carbon. 

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3. Inhibiting Asphaltene Deposition Using Polymer-Functionalized Nanoparticles in Microfluidic Porous Media

   https://doi.org/10.1021/acs.energyfuels.3c03060  

   Nguyen, Thao Vy; Zhang, Zhuqing; Wang, Jianxin; Sagi, Aparna; Kapoor, Yogesh; Terlier, Tanguy; Biswal, Sibani Lisa (December 2023, Energy & Fuels)

   Asphaltenes are the heaviest and most polarizable fractions of crude oil. During the oil production process, changes in the temperature, pressure, and oil composition can destabilize asphaltenes. This destabilization leads to asphaltene aggregation and deposition, which can cause major clogging problems in both the wellbore and near-wellbore regions as well as the production facilities. In this study, we developed and investigated the application of acrylic acid and 2-acrylanmido-2-methylpropanesulfonic acid (AA–AMPS)-functionalized magnetic nanoparticles as a surface coating in inhibiting asphaltene deposition. The use of the porous media microfluidic platform allows for efficient evaluation of the effectiveness of the nanoparticle coating in mitigating asphaltene deposition in various crude oils. We demonstrated that the nanoparticle coating is effective in inhibiting asphaltene deposition, showing up to a 75% improvement in permeability change. The study also explores the dynamics of asphaltene aggregation and deposition in different crude oils. We identified factors such as asphaltene aggregate size as well as the physical and chemical characteristics of the aggregates that can determine the effectiveness of different mitigation methods. 

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4. Hybrid Huff-n-Puff Process for Enhanced Oil Recovery: Integration of Surfactant Flooding with CO2 Oil Swelling

   https://doi.org/10.3390/app142412078  

   Ratanpara, Abhishek; Donjuan, Joshua; Smith, Camron; Procak, Marcellin; Aboubakar, Ibrahima; Mandin, Philippe; Al-Raoush, Riyadh I; Inguanta, Rosalinda; Kim, Myeongsub (December 2024, Applied Sciences)

   With increasing energy demands and depleting oil accessibility in reservoirs, the investigation of more effective enhanced oil recovery (EOR) methods for deep and tight reservoirs is imminent. This study investigates a novel hybrid EOR method, a synergistic approach of nonionic surfactant flooding with intermediate CO2-based oil swelling. This study is focused on the efficiency of surfactant flooding and low-pressure oil swelling in oil recovery. We conducted a fluorescence-based microscopic analysis in a microchannel to explore the effect of sodium dodecyl sulfate (SDS) surfactant on CO2 diffusion in Texas crude oil. Based on the change in emission intensity of oil, the results revealed that SDS enhanced CO2 diffusion at low pressure in oil, primarily due to SDS aggregation and reduced interfacial tension at the CO2 gas–oil interface. To validate the feasibility of our proposed EOR method, we adopted a ‘reservoir-on-a-chip’ approach, incorporating flooding tests in a polymethylmethacrylate (PMMA)-based micromodel. We estimated the cumulative oil recovery by comparing the results of two-stage surfactant flooding with intermediate CO2 swelling at different pressures. This novel hybrid approach test consisted of a three-stage sequence: an initial flooding stage, followed by intermediate CO2 swelling, and a second flooding stage. The results revealed an increase in cumulative oil recovery by nearly 10% upon a 2% (w/v) solution of SDS and water flooding compared to just water flooding. The results showed the visual phenomenon of oil imbibition during the surfactant flooding process. This innovative approach holds immense potential for future EOR processes, characterized by its unique combination of surfactant flooding and CO2 swelling, yielding higher oil recovery. 

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5. Fabrication and verification of a glass–silicon–glass micro-/nanofluidic model for investigating multi-phase flow in shale-like unconventional dual-porosity tight porous media

   https://doi.org/10.1039/C9LC00847K  

   Zhang, Yandong; Zhou, Chuanle; Qu, Chuang; Wei, Mingzhen; He, Xiaoming; Bai, Baojun (December 2019, Lab on a Chip)

   Unconventional shale or tight oil/gas reservoirs that have micro-/nano-sized dual-scale matrix pore throats with micro-fractures may result in different fluid flow mechanisms compared with conventional oil/gas reservoirs. Microfluidic models, as a potential powerful tool, have been used for decades for investigating fluid flow at the pore-scale in the energy field. However, almost all microfluidic models were fabricated by using etching methods and very few had dual-scale micro-/nanofluidic channels. Herein, we developed a lab-based, quick-processing and cost-effective fabrication method using a lift-off process combined with the anodic bonding method, which avoids the use of any etching methods. A dual-porosity matrix/micro-fracture pattern, which can mimic the topology of shale with random irregular grain shapes, was designed with the Voronoi algorithm. The pore channel width range is 3 μm to 10 μm for matrices and 100–200 μm for micro-fractures. Silicon is used as the material evaporated and deposited onto a glass wafer and then bonded with another glass wafer. The channel depth is the same (250 nm) as the deposited silicon thickness. By using an advanced confocal laser scanning microscopy (CLSM) system, we directly visualized the pore level flow within micro/nano dual-scale channels with fluorescent-dyed water and oil phases. We found a serious fingering phenomenon when water displaced oil in the conduits even if water has higher viscosity and the residual oil was distributed as different forms in the matrices, micro-fractures and conduits. We demonstrated that different matrix/micro-fracture/macro-fracture geometries would cause different flow patterns that affect the oil recovery consequently. Taking advantage of such a micro/nano dual-scale ‘shale-like’ microfluidic model fabricated by a much simpler and lower-cost method, studies on complex fluid flow behavior within shale or other tight heterogeneous porous media would be significantly beneficial. 

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