Low Tension Gas Process in High Salinity and Low Permeability Reservoirs

Das, Alolika; Nguyen, Nhut; Alkindi, Abdullah; Farajzadeh, R.; Azri, Nasser; Southwick, J. G.; Vincent-Bonnieu, S.; Nguyen, Quoc P.

doi:10.2118/179839-ms

Cited by 18 publications

(1 citation statement)

References 19 publications

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“…Iglauer et al (2004) also successfully studied APGs for microemulsion phase behavior experiments at 30 °C and 110,000 ppm salinity. Das et al (2016) were the first to successfully demonstrate the applicability of APG surfactants in LTG flooding in high-salinity (above 200,000 ppm) environments.…”

Section: Aqueous Stability and Microemulsion Phase Behavior Testsmentioning

confidence: 99%

Low-tension gas process in high-salinity and low-permeability reservoirs

Das¹,

Nguyen²,

Nguyen³

2020

Pet. Sci.

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Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics.

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Section: Aqueous Stability and Microemulsion Phase Behavior Testsmentioning

confidence: 99%

Low-tension gas process in high-salinity and low-permeability reservoirs

Das¹,

Nguyen²,

Nguyen³

2020

Pet. Sci.

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Performance of surfactant blend formulations for controlling gas mobility and foam propagation under reservoir conditions

Memon

Elraies

Al-Mossawy

2020

J Petrol Explor Prod Technol

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The use of surfactant is one of the possible solutions to minimize the mobility of gases and improve the sweep efficiency, but the main problem with this process is its stability in the presence of injection water and crude oil under reservoir conditions. In this study, the three types of surfactant anionic, nonionic and amphoteric are examined in the presence of brine salinity at 96 °C and 1400 psia. To access the potential blended surfactant solutions as gas mobility control, laboratory test including aqueous stability, interfacial tension (IFT) and mobility reduction factor (MRF) were performed. The purpose of MRF is to evaluate the blocking effect of selected optimum surfactant solutions. Based on experimental results, no precipitation was observed by testing the surfactant solutions at reservoir temperature of 96 °C. The tested surfactant solutions reduced the IFT between crude oil and brine. The effectiveness and strength of surfactant solutions without crude oil under reservoir conditions were evaluated. A high value of differential pressure demonstrates that the strong foam was generated inside a core that resulted in delay in breakthrough time and reduction in the gas mobility. High mobility reduction factor result was measured by the solution of blended surfactant 0.6%AOS + 0.6%CA406H. Mobility reduction factor of other tested surfactant solutions was found low due to less generated foam by using CO2 under reservoir conditions. The result of these tested surfactant solutions can provide the better understanding of the mechanisms behind generated foam stability and guideline for their implementation as gas mobility control during the process of surfactant alternating gas injection.

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