Surfactant–Polymer Flooding: Influence of the Injection Scheme

Druetta, Pablo; Picchioni, Francesco

doi:10.1021/acs.energyfuels.8b02900

Cited by 39 publications

(34 citation statements)

References 55 publications

(109 reference statements)

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“…Similar results were found by Ye [8] when studying the interaction of hydrophobically associating polyacrylamide and dodecyl dimethyl betaine (zwitterionic), observing that the air-water surface tension and oil-water IFT are reduced by the polymer presence due to the fact that the latter forms a network in the aqueous solution with the surfactant. Polymer-Surfactant interactions and their effect on the IFT (Adapted from Druetta [9]).…”

Section: Polymer-surfactant Flooding and Interactionmentioning

confidence: 99%

Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding

Druetta

Picchioni

2020

Energies

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The traditional Enhanced Oil Recovery (EOR) processes allow improving the performance of mature oilfields after waterflooding projects. Chemical EOR processes modify different physical properties of the fluids and/or the rock in order to mobilize the oil that remains trapped. Furthermore, combined processes have been proposed to improve the performance, using the properties and synergy of the chemical agents. This paper presents a novel simulator developed for a combined surfactant/polymer flooding in EOR processes. It studies the flow of a two-phase, five-component system (aqueous and organic phases with water, petroleum, surfactant, polymer and salt) in porous media. Polymer and surfactant together affect each other’s interfacial and rheological properties as well as the adsorption rates. This is known in the industry as Surfactant-Polymer Interaction (SPI). The simulations showed that optimum results occur when both chemical agents are injected overlapped, with the polymer in the first place. This procedure decreases the surfactant’s adsorption rates, rendering higher recovery factors. The presence of the salt as fifth component slightly modifies the adsorption rates of both polymer and surfactant, but its influence on the phase behavior allows increasing the surfactant’s sweep efficiency.

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Section: Polymer-surfactant Flooding and Interactionmentioning

confidence: 99%

Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding

Druetta

Picchioni

2020

Energies

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“…Field application is straightforward, performed only with a simple injection pump, instead of more complicated surfactant injection facilities [97]. For both patterns, the initial nanofluid formulation included 1000 and 100 mg•L −1 of the SA surfactant and CNA nanoparticles, respectively.…”

Section: Field Applicationmentioning

confidence: 99%

Design and Tuning of Nanofluids Applied to Chemical Enhanced Oil Recovery Based on the Surfactant–Nanoparticle–Brine Interaction: From Laboratory Experiments to Oil Field Application

et al. 2020

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The primary objective of this study is to develop a novel experimental nanofluid based on surfactant–nanoparticle–brine tuning, subsequently evaluate its performance in the laboratory under reservoir conditions, then upscale the design for a field trial of the nanotechnology-enhanced surfactant injection process. Two different mixtures of commercial anionic surfactants (SA and SB) were characterized by their critical micelle concentration (CMC), density, and Fourier transform infrared (FTIR) spectra. Two types of commercial nanoparticles (CNA and CNB) were utilized, and they were characterized by SBET, FTIR spectra, hydrodynamic mean sizes (dp50), isoelectric points (pHIEP), and functional groups. The evaluation of both surfactant–nanoparticle systems demonstrated that the best performance was obtained with a total dissolved solid (TDS) of 0.75% with the SA surfactant and the CNA nanoparticles. A nanofluid formulation with 100 mg·L−1 of CNA provided suitable interfacial tension (IFT) values between 0.18 and 0.15 mN·m−1 for a surfactant dosage range of 750–1000 mg·L−1. Results obtained from adsorption tests indicated that the surfactant adsorption on the rock would be reduced by at least 40% under static and dynamic conditions due to nanoparticle addition. Moreover, during core flooding tests, it was observed that the recovery factor was increased by 22% for the nanofluid usage in contrast with a 17% increase with only the use of the surfactant. These results are related to the estimated capillary number of 3 × 10−5, 3 × 10−4, and 5 × 10−4 for the brine, the surfactant, and the nanofluid, respectively, as well as to the reduction in the surfactant adsorption on the rock which enhances the efficiency of the process. The field trial application was performed with the same nanofluid formulation in the two different injection patterns of a Colombian oil field and represented the first application worldwide of nanoparticles/nanofluids in enhanced oil recovery (EOR) processes. The cumulative incremental oil production was nearly 30,035 Bbls for both injection patterns by May 19, 2020. The decline rate was estimated through an exponential model to be −0.104 month−1 before the intervention, to −0.016 month−1 after the nanofluid injection. The pilot was designed based on a production increment of 3.5%, which was successfully surpassed with this field test with an increment of 27.3%. This application is the first, worldwide, to demonstrate surfactant flooding assisted by nanotechnology in a chemical enhanced oil recovery (CEOR) process in a low interfacial tension region.

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“…However, the alkali in the ASP flooding system can cause some problems, which can restrict the application of ASP flooding. The alkali can react with rock mineral to cause severe scaling problems and promote the formation of water-in-oil (W/O) emulsion in the produced liquids that is too stable to be broken [31][32][33][34][35][36][37][38][39][40][41][42][43][44]. In addition, the high consumption of alkali for the heavy oil with low acid number, which will lead to saltsensitive effect and reduce the viscosity.…”

Section: Introductionmentioning

confidence: 99%

Insights into Enhanced Oil Recovery by Polymer-Viscosity Reducing Surfactant Combination Flooding in Conventional Heavy Oil Reservoir

Chen

et al. 2021

Geofluids

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Polymer flooding has a significant potential to enhance oil recovery in a light oil reservoir. However, for polymer flooding in a conventional heavy oil reservoir, due to unfavorable mobility ratio between water and oil, the improvement of sweep efficiency is limited, resulting in a low incremental oil recovery and failure to achieve high-efficiency development for polymer flooding in a conventional heavy oil reservoir. Inspired by the EOR mechanisms of the surfactant-polymer (SP) flooding process, the polymer-viscosity reducing surfactant flooding (P-VRSF) system was proposed to enhance conventional heavy oil recovery. Thus, to gain an insight into enhancing oil recovery by P-VRSF in a conventional heavy oil reservoir, the viscosity property, oil-water interfacial tension property, and oil viscosity reduction property were investigated. A series of parallel sand pack experiments were conducted to investigate enhanced oil recovery ability of polymer flooding and P-VRSF in a heterogeneous reservoir. Then, the 2D micromodel flooding experiments were conducted to investigate the EOR mechanism from porous media to pore level. Results demonstrated that polymer could increase the viscosity of injection water and improve the sweep efficiency. The emulsifying stability of surfactant with ultralow IFT (10-3 mN/m) was worse than that of the surfactant with higher IFT (10-2 mN/m). The viscosity reduction rate of the surfactant with higher IFT was higher than 80% at different oil-water volume ratios. The incremental oi recovery of P-VRSF was higher than that of polymer flooding. Moreover, the polymer-viscosity reducing surfactant with higher IFT could have higher incremental oil recovery. The 2D micromodel flooding results showed that the swept area of polymer flooding and P-VRSF was larger than that of water flooding. Moreover, the swept area of the surfactant with good emulsifying stability was larger than that of the surfactant with ultralow IFT. These findings could provide insights into enhancing oil recovery by P-VRSF in the conventional heavy oil reservoir.

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Surfactant–Polymer Flooding: Influence of the Injection Scheme

Cited by 39 publications

References 55 publications

Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding

Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding

Design and Tuning of Nanofluids Applied to Chemical Enhanced Oil Recovery Based on the Surfactant–Nanoparticle–Brine Interaction: From Laboratory Experiments to Oil Field Application

Insights into Enhanced Oil Recovery by Polymer-Viscosity Reducing Surfactant Combination Flooding in Conventional Heavy Oil Reservoir

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