Chemical Flooding in Naturally Fractured Reservoirs: Fundamental Aspects and Field-Scale Practices

Jamaloei, Benyamin Yadali

doi:10.2516/ogst/2010040

Cited by 23 publications

(6 citation statements)

References 95 publications

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“…Many factors influence the performance of surfactant-based chemical flooding processes. These factors include the type and formulation of the surfactant, stability, phase behavior, chemical loss and adsorption, wettability, reservoir rock morphology, and heterogeneity . The involved phase equilibrium is a key factor in understanding the know-how of oil recovery by these processes.…”

Section: Introductionmentioning

confidence: 99%

Enhanced Oil Recovery with the Ionic Liquid Trihexyl(tetradecyl)phosphonium Chloride: A Phase Equilibria Study at 75 °C

et al. 2013

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The enhanced oil recovery (EOR) through microemulsion flooding implies the formulation of a complex aqueous mixture containing surfactants, co-surfactants, cosolvents, or viscosity-increasing polymers, among other additives. The optimal formulation is associated with a three-phase behavior, in which the interfacial tension becomes significantly low. One parameter that greatly affects this formulation is the temperature. In this work, it has been shown that the three-phase system generated when adding trihexyl(tetradecyl)phosphonium chloride ionic liquid to a water−oil mixture remains stable in a wide range of temperatures and in the presence of salt. In contrast to conventional systems, no co-surfactant is required. This thermal stability is an interesting feature from the EOR point of view. The use of higher temperatures implies that a slightly minor quantity of ionic liquid is needed to solubilize the water and oil mixtures. Moreover, when the temperature is increased, there is an important decrease of the microemulsion−water/brine interfacial tension and a mild decrease in the case of the microemulsion−oil. The trihexyl(tetradecyl)phosphonium chloride ionic liquid was proven to be an effective surface-active agent to recover oil.

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Section: Introductionmentioning

confidence: 99%

Enhanced Oil Recovery with the Ionic Liquid Trihexyl(tetradecyl)phosphonium Chloride: A Phase Equilibria Study at 75 °C

et al. 2013

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“…There are two flow regimes in a naturally fractured carbonate reservoir, which can be characterized by a highly permeable fracture zone surrounding a low-permeability matrix zone. − Water flooding is the easiest and cheapest approach used to enhance the production of oil from water-wet reservoirs. However, most fractured carbonate reservoirs are oil-wet, which makes conditions complex and critical, resulting in poor rates of oil recovery. , In fractured carbonate reservoirs, oil production mainly depends on the water imbibition process to extract the oil present from the matrix network toward the fracture zone. There are several parameters that can affect the imbibition process, such as boundary conditions and the size and shape, matrix permeability, and heterogeneity of the reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Application of Water-Soluble Polymer/Biopolymer Combined with a Biosurfactant in Oil-Wet Fractured Carbonate Reservoirs

et al. 2021

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Most fractured carbonate reservoirs are characterized by a highly permeable fracture zone surrounded by a low-permeability oil-wet matrix. These features make the displacement of oil from the matrix into the fracture zone almost impossible during water flooding. This paper presents the results of flooding with the polymer polyacrylamide (PAM) and the biopolymer xanthan gum (XG) in combination with a biosurfactant to enhance water imbibition into oil-wet fractured carbonate rocks. Core flooding experiments were conducted on induced horizontally fractured (at 180°) carbonate cores in room conditions (20 ± 2 °C). The polymer or biopolymer was used to plug the fracture zones, while the biosurfactant was added to the system to alter the wettability state of the rock matrix from oil-wet to water-wet. Rock surface characterization before and after core flooding was conducted using scanning electron microscopy (SEM). The results indicate that PAM flooding led to a higher reduction of 35.6% in fracturematrix permeability than that with XG at 18.3%. The monitoring of oil production also showed that ultimate oil recovery levels from oil-wet fractured carbonate cores for the aforementioned systems were 16 and 8.7%, respectively, which can be attributed to the drive mechanisms of temporary fracture plugging as well as mobility ratio improvement due to the polymer and wettability alteration by the biosurfactant. SEM images confirm the proposed mechanisms, where the presence of the polymer/biopolymer followed by the biosurfactant can be detected at the rock surface as a result of chemical flow through the system.

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“…In addition, the governing mechanisms in chemical flooding methods have been investigated and reported. Wettability alteration towards water‐wet, changing oil‐water interfacial tension, and improving sweep efficiency by controlling mobility ratio were introduced as the most discussed governing mechanisms in chemical flooding method …”

Section: Introductionmentioning

confidence: 99%

“…Such chemicals, when added to the injecting fluid can alter the wettability of reservoir rock to water‐wet and can reduce the interfacial tension between the water and reservoir oil . Jamaloei performed a broad review of EOR methods using chemical flooding specially in carbonate reservoirs. The various methods of chemical flooding including polymer, surfactant, and/or alkali flooding or combinations of these methods have been fully discussed.…”

Section: Introductionmentioning

confidence: 99%

Effects of Nanoparticles on Gas Production, Viscosity Reduction, and Foam Formation during Nanofluid Alternating Gas Injection in Low and High Permeable Carbonate Reservoirs

et al. 2016

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Some carbonate reservoirs are low‐permeable and mixed‐wet to oil‐wet. Application of enhanced recovery methods to decrease residual oil saturation is the main challenge in such reservoirs. Water‐flooding is not an appropriate method to improve the recovery due to the wettability of carbonate reservoirs. Water alternating gas (WAG) injection is used as another method but it faces some problems. To enhance the performance of the WAG method, the wettability of rock should be changed and mobility of the injected gas should be controlled. In our previous study (Moradi et al.[32]), to improve the WAG‐EOR process and overcome the problems, we developed the nanofluid‐alternating gas (NWAG) approach by adding nanoparticles to the aqueous phase. Our study indicated that the NWAG process could improve oil recovery in comparison to the conventional WAG method in different core samples with different lithology and permeability. In this study, core‐flooding experiments, dynamic foam generation, and viscosity measurement were performed to investigate the effect of nanoparticles on gas production, viscosity reduction, and possibility of foam formation in the NWAG process. The results indicated that the gas production was decreased in the NWAG process. In addition, viscosity of produced oil was lower in the NWAG process; CO2 dissolved in the oil and led to oil swelling and oil viscosity reduction. Oil recovery was higher in the samples with lower permeability due to the formation of foam in the porous media. Foam formation increased viscosity and controlled mobility, which led to better sweep efficiency.

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Chemical Flooding in Naturally Fractured Reservoirs: Fundamental Aspects and Field-Scale Practices

Cited by 23 publications

References 95 publications

Enhanced Oil Recovery with the Ionic Liquid Trihexyl(tetradecyl)phosphonium Chloride: A Phase Equilibria Study at 75 °C

Enhanced Oil Recovery with the Ionic Liquid Trihexyl(tetradecyl)phosphonium Chloride: A Phase Equilibria Study at 75 °C

Application of Water-Soluble Polymer/Biopolymer Combined with a Biosurfactant in Oil-Wet Fractured Carbonate Reservoirs

Effects of Nanoparticles on Gas Production, Viscosity Reduction, and Foam Formation during Nanofluid Alternating Gas Injection in Low and High Permeable Carbonate Reservoirs

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