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

Barnes, Julian Richard; Smit, Johan; Smit, Jasper; Shpakoff, Greg; Raney, Kirk H.; Puerto, Maura

doi:10.2118/113314-ms

Cited by 17 publications

(14 citation statements)

References 3 publications

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“…Barnes et al 16 evaluated the results IOS with different carbon numbers using improved phase behavior experimental methods and showed that IOS family of surfactants had good chemical stability at higher temperatures (up to 150°C) and high solubilization of oil at their optimal salinities. However high critical micelle concentration (CMC) and limited salinity tolerance are the main drawbacks of anionic surfactant, which make them inappropriate for applying at high concentrations of divalent ions 17 .…”

Section: Introductionmentioning

confidence: 99%

Synthesis of stable nanoparticles at harsh environment using the synergistic effect of surfactants blend

Nourafkan

Asachi

et al. 2018

Journal of Industrial and Engineering Chemistry

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Section: Introductionmentioning

confidence: 99%

Synthesis of stable nanoparticles at harsh environment using the synergistic effect of surfactants blend

Nourafkan

Asachi

et al. 2018

Journal of Industrial and Engineering Chemistry

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“…The substantial shear-thinning flow behavior and suitable values of dynamic viscosities (i.e., viscosity values that are not too high and/or too low relative to the viscosity of the oil) ensure stable microemulsion systems that effectively propagate through the sand-packs, forming a stable displacement front that displaces oil more effectively with a low risk of microemulsion phase fingering and/or trapping within the porous media. 6,12,27,30,53,66 Moreover, in this work, the optimum formulations were prepared by blending a straight chain surfactant (i.e., SDS) and a branched chain surfactant (i.e., Alfoterra 167-4s) that creates disorder in the mixture, avoiding the formation of highly viscous micellar structures (i.e., gel-like phases). 6,21,29,71 Samples of both optimum formulations have been kept for a period of 4 years at room temperature to evaluate the stability of the middle microemulsion phases (i.e., Winsor Type III).…”

Section: Resultsmentioning

confidence: 99%

Formulation of an Encapsulated Surfactant System, ESS, via β-CD Host–Guest Interactions to Inhibit Surfactant Adsorption onto Solid Surfaces

Romero‐Zerón

Wadhwani

Sethiya

2020

Ind. Eng. Chem. Res.

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In this work, the issue of surfactant adsorption (SA) onto solid surfaces was attempted through surfactant encapsulation via host−guest interactions using β-CD. Formulations of a nonencapsulated surfactant system (Non-ESS) and an encapsulated surfactant system (ESS) were obtained through phase behavior analysis. Rheology shows that the ESS and Non-ESS display low viscosities, shear-thinning flow behavior, and structural stability. The ESS and Non-ESS were applied as surfactant flooding for enhanced oil recovery via coreflooding displacement tests to evaluate their performances in displacing and recovering residual oil. Static and dynamic SA tests of the ESS and Non-ESS were conducted. The experimental results demonstrate the effective propagation of both systems through the sand-packs. At the same flooding conditions, the ESS produced 63% higher incremental oil recovery than the Non-ESS, which confirms a reduced SA and effective surfactant release from the β-CD in the presence of oil. The static SA tests indicate that the ESS reduced SA by 82.42%, 60.59%, and 6.73% onto sand, kaolin, and shale respectively, relative to the Non-ESS. Likewise, the dynamic SA tests demonstrate that the ESS reduced SA onto sand−kaolin surfaces by 43.3% relative to the Non-ESS. Consequently, the ESS shows potential for applications where SA onto solid surfaces is a critical issue.

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“…A number of previous papers have characterized this work very well (including: Wade, et al, 1978;Barnes, et al;Solairaj, et al, 2012, etc.). New research on phase behavior and IFT at high temperature ( ～ 120°C) and high salinity ( ～ 20 % TDS) show that: with NaCl and n-octane oil mixed with alkoxyglycidylether (AGES) sulfonate anionic surfactants (free of alcohol and other co-solvents), classical Winsor phase behavior and optimal salinity were observed, providing ultra-low IFTs (Puerto, et al, 2011).…”

Section: Introductionmentioning

confidence: 86%

Optimal Salinity Study to Support Surfactant Imbibition into the Bakken Shale

2013

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In our previous study of Bakken shale imbibition, a group of surfactant formulations were examined. These surfactants consistently altered the wetting state of Bakken cores toward water-wet, and appeared to have a substantial potential to improve oil recovery from the Bakken Formation compared to brine water alone. To advance this development, this paper investigates the optimal salinities of surfactant solutions by phase behavior and IFT studies using Bakken formation water and oil. The ultimate objective of this research is to determine the potential for surfactant formulations to imbibe into and displace oil from shale, and also examine the viability of a field application.Using glass tube and encased-pipette methods, as well as a spinning drop tensiometer, dilute surfactant formulations were studied with various surfactants molecular structures (anionic, nonionic, cationic, and amphoteric). In most cases, optimal salinities obtained by phase behavior and IFT study aid surfactant imbibition into the Bakken Shale. In other cases, surfactant formulations were effective in imbibing into and displacing Bakken oil from Bakken cores, even though there were no obvious optimal salinities observed-suggesting that wettability alteration was a more dominant mechanism than IFT reduction in the imbibition process. Where optimal salinity behavior was obtained, the IFT between surfactant water and crude oil were reduced by one to two orders of magnitude with alkaline formulations. Under the same conditions, the inverse Bond number N B -1 which dominates the displacement mechanism, could be decreased below a value of 1 in cores from the Middle member of the Bakken.Based on phase behavior and IFT measurement at optimal salinity, we found: for Bakken reservoir conditions, (1) at lower concentrations (0.1%), of an anionic surfactant, internal olefin sulfonate shows a fast imbibition rate but lower oil recovery compared with a higher concentration surfactant (2%) with same molecular structure. (2) With 0.1% concentration, nonionic surfactants with an ethoxylated alcohol molecular structure exhibit a fast imbibition rate and strong effect on oil recovery at reservoir temperature (~120°C). (3) A cationic surfactant with a large carbon number and ethoxylated tallow amine structure at 0.1 % concentration has a favorable effect on oil production at high temperature. (4) An amphoteric surfactant with dimethyl amine oxide structure shows a stronger effect on oil recovery at 0.1% concentration. (5) At optimal salinity, the incremental oil recovery (during imbibition into Bakken cores at 120°C) can be up to 18% OOIP higher than seen during comparable experiments using formulations with 15～30% TDS, and the average instantaneous imbibition rate increased up to 45%.

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

Cited by 17 publications

References 3 publications

Synthesis of stable nanoparticles at harsh environment using the synergistic effect of surfactants blend

Synthesis of stable nanoparticles at harsh environment using the synergistic effect of surfactants blend

Formulation of an Encapsulated Surfactant System, ESS, via β-CD Host–Guest Interactions to Inhibit Surfactant Adsorption onto Solid Surfaces

Optimal Salinity Study to Support Surfactant Imbibition into the Bakken Shale

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