Experimental Study on Switchable Acetamidine Surfactant Flooding in Sandstone Using NMR

Feng, Pang; Wang, Linlin; Hou, Qingfeng; Ma, Sihang; Cheng, Jiuhui

doi:10.1021/acs.energyfuels.2c02727

Cited by 6 publications

(2 citation statements)

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“…The injection of water into hydrocarbon reservoirs is a commonly employed method to increase oil recovery and maintain the reservoir pressure. Nonetheless, owing to the substantial interfacial tension (IFT) between the injected water and the oil in place, a significant portion of the crude oil remains in place, leading to ineffective recovery . Therefore, the need to reduce the oil/water IFT is inevitable for better oil displacement.…”

Section: Introductionmentioning

confidence: 99%

“…Nonetheless, owing to the substantial interfacial tension (IFT) between the injected water and the oil in place, a significant portion of the crude oil remains in place, leading to ineffective recovery. 11 Therefore, the need to reduce the oil/water IFT is inevitable for better oil displacement. The IFT can be reduced by the addition of surfactant to the injected water as a chemical EOR (cEOR) process.…”

Section: Introductionmentioning

confidence: 99%

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Role of Injection Rate on Chemically Enhanced Oil Recovery Using a Gemini Surfactant under Harsh Conditions

Al-Azani,

Abu-Khamsin,

Kamal

et al. 2024

Energy Fuels

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Introducing surfactants into a hydrocarbon reservoir is considered one of the most effective methods for enhanced oil recovery (EOR), mainly due to their ability to reduce interfacial tension and modify rock wettability. However, experimental parameters play a significant role in surfactant flooding. As an important design parameter, this work specifically investigates how the injection rate influences the oil recovery performance of a locally synthesized Gemini surfactant. Four core flooding experiments on carbonate core samples were conducted, each at a specific injection rate (0.10, 0.25, 0.50, and 1.00 cc/min) under simulated reservoir conditions. The conditions include a temperature of 100 °C, pressures exceeding 3000 psi, and formation water and seawater salinities of 213,768 and 57,745 ppm, respectively. Each experiment involved initial continuous seawater flooding followed by continuous flooding with a 2500 ppm surfactant solution. The results revealed an increasing trend in the recovery factor with injection rates caused by seawater flooding. Recovery factors at 0.10, 0.25, and 0.50 cc/min rates were 43.7, 46.6, and 49.1% of the oil initially in place (OOIP), respectively. However, at 1.00 cc/min, the factor decreased to 48.1% OOIP after seawater flooding, possibly due to poor conformance control. In contrast, the recovery factor at the end of surfactant flooding was higher at lower injection rates (i.e., 0.10 and 0.25 cc/min), reflecting sufficient time for the surfactant to alter rock wettability and mobilize oil with 0.25 cc/min as the optimum tested rate. However, effluent analysis revealed that slower injection rates correlated with higher dynamic retention (e.g., 0.383 mg/g of rock at 0.10 cc/min) compared to higher injection rates (e.g., 0.295 mg/g of rock at 1.00 cc/ min). This implies a trade-off in choosing the injection rate when using the Gemini surfactant: balancing high oil recovery against minimizing dynamic retention. Consequently, this study emphasizes the need to carefully consider injection rates in surfactant flooding for optimal EOR outcomes.

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Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%