Development of Surfactants for Chemical Flooding at Difficult Reservoir Conditions

2008 ◽  
Author(s):  
Julian Richard Barnes ◽  
Johan Smit ◽  
Jasper Smit ◽  
Greg Shpakoff ◽  
Kirk H. Raney ◽  
...  
Keyword(s):  
Chemical Flooding ◽  
Reservoir Conditions

Oil emulsion characteristics as significance in efficiency forecast of oil-displacing formulations based on surfactants

2021 ◽  
pp. 91-107
Author(s):  
E. A. Turnaeva ◽  
E. A. Sidorovskaya ◽  
D. S. Adakhovskij ◽  
E. V. Kikireva ◽  
N. Yu. Tret'yakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Concentration ◽  
Chemical Flooding ◽  
Optimal Salinity ◽  
Oil Emulsion ◽  
Oil Displacement ◽  
Laboratory Selection ◽  
Reservoir Conditions ◽  
Selection Of ◽  
Comprehensive Study

Enhanced oil recovery in mature fields can be implemented using chemical flooding with the addition of surfactants using surfactant-polymer (SP) or alkaline-surfactant-polymer (ASP) flooding. Chemical flooding design is implemented taking into account reservoir conditions and composition of reservoir fluids. The surfactant in the oil-displacing formulation allows changing the rock wettability, reducing the interfacial tension, increasing the capillary number, and forming an oil emulsion, which provides a significant increase in the efficiency of oil displacement. The article is devoted with a comprehensive study of the formed emulsion phase as a stage of laboratory selection of surfactant for SP or ASP composition. In this work, the influence of aqueous phase salinity level and the surfactant concentration in the displacing solution on the characteristics of the resulting emulsion was studied. It was shown that, according to the characteristics of the emulsion, it is possible to determine the area of optimal salinity and the range of surfactant concentrations that provide increased oil displacement. The data received show the possibility of predicting the area of effectiveness of ASP and SP formulations based on the characteristics of the resulting emulsion.

Phase Behaviour Methods for the Evaluation of Surfactants for Chemical Flooding at Higher Temperature Reservoir Conditions

2008 ◽  
Author(s):  
Julian Richard Barnes ◽  
Johan Smit ◽  
Jasper Smit ◽  
Greg Shpakoff ◽  
Kirk H. Raney ◽  
...  
Keyword(s):  
Phase Behaviour ◽  
Chemical Flooding ◽  
Reservoir Conditions ◽  
Higher Temperature

scholarly journals Assessment of xanthan gum and xanthan-g-silica derivatives as chemical flooding agents and rock wettability modifiers

2020 ◽  
Vol 75 ◽  
pp. 12 ◽  
Author(s):  
Ahmed Ashraf Soliman ◽  
Abdelaziz Nasr El-hoshoudy ◽  
Attia Mahmoud Attia
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Xanthan Gum ◽  
Water Saturation ◽  
Chemical Characterization ◽  
Spectroscopic Methods ◽  
Chemical Flooding ◽  
Reservoir Conditions ◽  
Relative Permeability Curves ◽  
Underground Reservoirs

Currently, biomolecules flooding in the underground reservoirs acquires sustainable interest owing to their availability and eco-friendly properties. The current study reported chemical displacement by xanthan gum as well as xanthan/SiO2 and xanthan grafted with vinylsilane derivatives. Chemical characterization evaluated by traditional spectroscopic methods. Investigation of fluids response to reservoir environment assessed through rheological performance relative to shearing rate, ionic strength, and thermal stability. A sequence of flooding runs generated on 10 sandstone outcrops with different porosity and permeabilities. Core wetness assessed through relative permeability curves at different water saturation. The flooding tests indicate that grafting of the silica derivative overcome the shortage of xanthan solution in flooding operations relative to the reservoir conditions. The ability of the flooding solutions to alter rock wettability explored through relative permeability curves at different water saturation. The results reveal that the synthesized composite was a promised agent for enhancing oil recovery and profile conformance.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

scholarly journals CO2 Convective Dissolution in Oil-Saturated Unconsolidated Porous Media at Reservoir Conditions

Energies ◽  
2021 ◽  
Vol 14 (1) ◽  
pp. 233
Author(s):  
Widuramina Amarasinghe ◽  
Ingebret Fjelde ◽  
Nils Giske ◽  
Ying Guo
Keyword(s):  
Porous Media ◽  
Crude Oil ◽  
Water Solution ◽  
Co2 Storage ◽  
Bromothymol Blue ◽  
Power Relationship ◽  
Dimensionless Time ◽  
3 Dimensional ◽  
Reservoir Conditions ◽  
Unconsolidated Porous Media

During CO2 storage, CO2 plume mixes with the water and oil present at the reservoir, initiated by diffusion followed by a density gradient that leads to a convective flow. Studies are available where CO2 convective mixing have been studied in water phase but limited in oil phase. This study was conducted to reach this gap, and experiments were conducted in a vertically packed 3-dimensional column with oil-saturated unconsolidated porous media at 100 bar and 50 °C (representative of reservoir pressure and temperature conditions). N-Decane and crude oil were used as oils, and glass beads as porous media. A bromothymol blue water solution-filled sapphire cell connected at the bottom of the column was used to monitor the CO2 breakthrough. With the increase of the Rayleigh number, the CO2 transport rate in n-decane was found to increase as a function of a second order polynomial. Ra number vs. dimensionless time τ had a power relationship in the form of Ra = c×τ−n. The overall pressure decay was faster in n-decane compared to crude oil for similar permeability (4 D), and the crude oil had a breakthrough time three times slower than in n-decane. The results were compared with similar experiments that have been carried out using water.

A nano‐Fe 3 O 4 material coated with AM / AMPS copolymer for viscosity enhancement at harsh reservoir conditions

2021 ◽  
pp. 50601
Author(s):  
Wenlong Qin ◽  
Ruixuan Li ◽  
Hanxi Li ◽  
Guanfeng Jiang ◽  
Guowei Qin ◽  
...  
Keyword(s):  
Reservoir Conditions ◽  
Viscosity Enhancement
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