Effects of water flooding speed on oil recovery efficiency and residual oil distribution in heterogeneous reservoirs

Jiang, Ziran; Ren, Hao; Maimaitiming, Duolikun; Wang, Zhaofeng; Dong, Hua

doi:10.1080/10916466.2022.2108837

Cited by 5 publications

(2 citation statements)

References 42 publications

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“…The imperative need for the development and evaluation of surfactants capable of withstanding high salinity and high-temperature (HTHS) reservoir conditions remains crucial. These conditions, coupled with other influential factors such as pH and rock lithology, significantly affect the efficacy of surfactant flooding techniques. , Design parameters like injection rate, surfactant concentration, slug size, and injection schemes are additional factors that impact the performance of surfactant flooding. , While various researchers have investigated the effects of injection rates in water flooding, − it is noteworthy that the influence of injection rates on oil recovery in surfactant flooding differs from its impact in traditional water flooding. This distinction arises due to the critical role of flow velocity and the duration of injection in surfactant flooding …”

Section: Introductionmentioning

confidence: 99%

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%

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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“…At present, research on enriched remaining oil mainly focuses on the distribution characteristics and influencing factors of enriched remaining oil after displacement (Xia et al, 2010, 2021; Tang et al, 2012; Fang et al, 2019; Wang et al, 2020; Zhao, 2021; Jiang et al, 2022), the recovery method of enriched remaining oil (Chen et al, 2013; Liu et al, 2022), and the remaining oil storage mechanism (Dai and Lin, 2020; Song et al, 2020; Wolf et al, 2020). Wang and Ye (2013) studied the distribution law of remaining oil after polymer flooding and proposed five remaining oil enrichment areas after polymer flooding.…”

Section: Introductionmentioning

confidence: 99%

Simulation analysis of the mechanism and influencing factors of remaining oil secondary enrichment in ultra-high water cut fault block reservoirs

Cui

et al. 2023

Energy Exploration & Exploitation

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After the near-abandoned production wells in the high part of the fault block reservoir are closed for a period of time, the remaining oil in the low part will accumulate at the fault in the high part to produce secondary enrichment. At present, research on the secondary enrichment of the remaining oil mainly focuses on the remigration method of the remaining oil, and there is less research on the mechanism of the secondary enrichment of the remaining oil. In view of the above problems, a planar numerical model is established to analyse the remaining oil secondary enrichment law, combined with the longitudinal numerical model to analyse the mechanism of the remaining oil secondary enrichment, and nine factors are selected to study their influence on the remaining oil secondary enrichment law, further determining the main control factors through sensitivity analysis. Based on the numerical simulation results, the reservoir conditions conducive to the secondary enrichment of the remaining oil are determined. The research shows that the remaining oil secondary enrichment mechanism includes pressure redistribution after well shut-in and the comprehensive effect of the micro force. The increase in the formation dip angle, permeability and water injection intensity before well shut-in is beneficial to accelerate the secondary enrichment of the remaining oil. Permeability and formation dip angle are the main controlling factors of positive correlation parameters, and the shut-in water cut is the main controlling factor of negative correlation parameters and the most sensitive. In addition, when the permeability is greater than 200 mD, the formation dip angle is greater than 9°, and the shut-in water cut is less than 95%, which is conducive to the secondary enrichment of the remaining oil. This study has reference significance for the field to understand the mechanism and influencing factors of the secondary enrichment of the remaining oil.

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Towards in-depth profile control using dispersed particle gels (DPGs)

Xiao

Jiang

et al. 2023

Fuel

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Effects of water flooding speed on oil recovery efficiency and residual oil distribution in heterogeneous reservoirs

Cited by 5 publications

References 42 publications

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

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

Simulation analysis of the mechanism and influencing factors of remaining oil secondary enrichment in ultra-high water cut fault block reservoirs

Towards in-depth profile control using dispersed particle gels (DPGs)

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