Enhanced oil recovery from high-temperature, high-salinity naturally fractured carbonate reservoirs by surfactant flood

Lu, Jun; Goudarzi, Ali; Chen, Peila; Kim, Do Hoon; Delshad, Mojdeh; Mohanty, Kishore K.; Sepehrnoori, Kamy; Weerasooriya, Upali; Pope, Gary A.

doi:10.1016/j.petrol.2014.10.016

Cited by 142 publications

(53 citation statements)

References 31 publications

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“…Thus, it was concluded that the wettability alteration by the biosurfactant is one of the major mechanisms of microbial enhanced oil recovery. The combined effects of the reduction in IFT and wettability alteration using surfactants have also been discussed in the literature (Anderson 1986;Alveskog et al 1998;Austad and Standnes 2003;Hirasaki and Zhang 2004;Kowalewski et al 2006;Zhang and Austad 2006;Lu et al 2014b). Kowalewski et al (2006) reported that changes in wetting properties are dependent on the initial wetting conditions where an initially oil-wet system can result in more water-wet conditions and vice versa.…”

Section: Coreflood Experiments Using Chemical Surfactant and Biosurfamentioning

confidence: 99%

“…Kowalewski et al (2006) reported that changes in wetting properties are dependent on the initial wetting conditions where an initially oil-wet system can result in more water-wet conditions and vice versa. Lu et al (2014b) reported a surfactant formulation (a novel large-hydrophobe alkoxy carboxylate surfactant and an internal olefin sulphonate co-surfactant) developed for carbonate reservoirs under high salinity and temperature, where it reduced the IFT to ultra-low values and also altered the wettability of the rock toward more favorable water-wet conditions, leading to enhanced oil recovery.…”

Section: Coreflood Experiments Using Chemical Surfactant and Biosurfamentioning

confidence: 99%

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Injection of biosurfactant and chemical surfactant following hot water injection to enhance heavy oil recovery

et al. 2015

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This study investigates the potential of enhancing oil recovery from a Middle East heavy oil field via hot water injection followed by injection of a chemical surfactant and/or a biosurfactant produced by a Bacillus subtilis strain which was isolated from oil-contaminated soil. The results reveal that the biosurfactant and the chemical surfactant reduced the residual oil saturation after a hot water flood. Moreover, it was found that the performance of the biosurfactant increased by mixing it with the chemical surfactant. It is expected that the structure of the biosurfactant used in this study was changed when mixed with the chemical surfactant as a probable synergetic effect of biosurfactant-chemical surfactants was observed on enhancing oil recovery, when used as a mixture, rather than alone. This work proved that it is more feasible to inject the biosurfactant as a blend with the chemical surfactant, at the tertiary recovery stage. This might be attributed to the fact that in the secondary mode, improvement of the macroscopic sweep efficiency is important, whereas in the tertiary recovery mode, the microscopic sweep efficiency matters mainly and it is improved by the biosurfactantchemical surfactant mixture. Also as evidenced by this study, the biosurfactant worked better than the chemical surfactant in reducing the residual heavy oil saturation after a hot water flood.

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Section: Coreflood Experiments Using Chemical Surfactant and Biosurfamentioning

confidence: 99%

Section: Coreflood Experiments Using Chemical Surfactant and Biosurfamentioning

confidence: 99%

Injection of biosurfactant and chemical surfactant following hot water injection to enhance heavy oil recovery

et al. 2015

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“…This contrast in permeability makes them challenging targets for chemical flooding. Also, some of these carbonate formations have high reservoir temperatures and contain high salinity formation brine (Lu et al 2014b). These multiple attributes coupled with their complex wettability conditions, i.e., oil-wet/mixed-wet surfaces, complicate reservoir characterization, production and management (Hirasaki and Zhang 2003).…”

Section: Introductionmentioning

confidence: 99%

Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

et al. 2017

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“…A wide range of surfactants have been evaluated over the past 30 years for enhanced oil recovery by performing static imbibition experiments. These studies have included tests with cationic surfactants (Austad and Milter, 1997;Standnes and Austad, 2000;Xie et al, 2005;Sharma and Mohanty, 2013), nonionic surfactants (Standnes et al, 2002;Xie et al, 2005;Gupta et al, 2010;Sharma and Mohanty, 2013), and anionic surfactants (Seethepalli et al, 2004;Nurkamelia and Arihara, 2004;Adibhatla and Mohanty, 2008;Gupta and Mohanty, 2010;Sharma and Mohanty, 2013;Chen and Mohanty, 2013;Wang and Mohanty, 2014;Lu et al, 2014). Austad et al (1998) used the cationic surfactant Dodecyl Trimethyl Ammonium Bromide (DTAB) and chalk cores with a diameter of 3.7 cm.…”

Section: Introductionmentioning

confidence: 99%

Scaling of Low IFT Imbibition in Oil-Wet Carbonates

Churchwell

et al. 2016

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Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.

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Enhanced oil recovery from high-temperature, high-salinity naturally fractured carbonate reservoirs by surfactant flood

Cited by 142 publications

References 31 publications

Injection of biosurfactant and chemical surfactant following hot water injection to enhance heavy oil recovery

Injection of biosurfactant and chemical surfactant following hot water injection to enhance heavy oil recovery

Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

Scaling of Low IFT Imbibition in Oil-Wet Carbonates

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