The Effect of Wettability on Waterflood Oil Recovery in Carbonate Rock Samples: A Systematic Multi-scale Experimental Investigation

Ekechukwu, Gerald Kelechi; Khishvand, Mahdi; Kuang, Wendi; Piri, Mohammad; Masalmeh, Shehadeh K.

doi:10.1007/s11242-021-01612-3

Cited by 22 publications

(9 citation statements)

References 68 publications

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“…This process was believed to be the cause of the aforementioned hysteresis. This unique observation is partly attributed to the pore structure of this rock type since it has not been reported in other research studies conducted on more homogeneous carbonate and sandstone rocks. , …”

Section: Resultsmentioning

confidence: 56%

“…This unique observation is partly attributed to the pore structure of this rock type since it has not been reported in other research studies conducted on more homogeneous carbonate and sandstone rocks. 49,50 The X-ray images were also used to generate in situ saturation data within the FOV, which are summarized in Table 3. The results indicate that the established initial water saturation in core sample S1 (23%) was lower than that in sample S2 (34%) even though the drainage processes were conducted using the same oil and at identical injection flow rates.…”

Section: ■ Materials and Methodsmentioning

confidence: 99%

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Synergistic Effects of Aqueous Phase Viscoelasticity and Reduced Interfacial Tension on Nonwetting Phase Displacement Efficiency: An In Situ Experimental Investigation

Khishvand

Piri

2023

Langmuir

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This study uses in situ experimental investigation techniques to probe the synergistic effects of aqueous phase viscoelasticity and reduced interfacial tension on nonwetting phase displacement efficiency in natural porous media. Specifically, it examines the efficacy of viscoelastic surfactant (VES) solutions in enhancing oil recovery and investigates the pore-scale displacement mechanisms and VES−oil interactions. To this end, we first performed an extensive rheological characterization to select two VES solutions from multiple CTAB/NaNO 3 (CTN) and Cocobetaine/SDS/ NaCl (CSN) mixtures. The selected aqueous solutions were then used in unsteady-state imbibition experiments conducted on miniature, water-wet Prairie Shell carbonate core samples. The experiments were performed utilizing a high-pressure, high-temperature two-phase core-flooding apparatus integrated with a high-resolution X-ray imaging system to acquire pore-scale fluid occupancy maps during the displacements. The results indicate that the injection of the selected CSN and CTN solutions into the carbonate samples under capillary-dominated flow regimes boosts the oil recovery by 12 and 2%, respectively, compared to those of the base waterflood. The VES solutions lowered the oil−water interfacial tension and exerted significant shear forces at the entrance of pores. The shear forces could exceed the threshold surface free energy required to deform oil globules, and consequently, large oil clusters were fragmented into smaller blobs and eventually produced from the pore space. The higher oil recovery by CSN flooding was attributed to its stronger viscoelastic properties. The VES injection under the viscous-dominated flow regime intensified the frequency of oil globule fragmentation. As a result, residual oil saturation values were sharply reduced in the rock samples from 44 to 55% during the capillary-dominated flows to approximately 8%. The above-mentioned observations were also verified using morphological analysis of residual oil clusters. The impacts of VES flooding on the pore-scale oil configuration and the fragmentation of large oil clusters were particularly evident at higher VES flow rates.

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Section: Resultsmentioning

confidence: 56%

Section: ■ Materials and Methodsmentioning

confidence: 99%

Synergistic Effects of Aqueous Phase Viscoelasticity and Reduced Interfacial Tension on Nonwetting Phase Displacement Efficiency: An In Situ Experimental Investigation

Khishvand

Piri

2023

Langmuir

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“…71,72 To establish a strongly oil-wet state, the rock samples were aged for 21 days by immersing them in crude oil at 100 °C under static conditions. 72 This aging process facilitates the adsorption of the polar components of oil onto the rock matrix.…”

Section: Experimental Workmentioning

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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“…This drainage process resulted in initial water saturations ranging from 32 to 35% in all rock samples confirming their homogeneous nature. Such relatively high initial saturations can be attributed to microporosity in the cores, which is characteristic of many carbonate rocks. , The samples were then aged for 3 weeks (∼21 days) under static conditions by immersion in the crude oil and kept at 100 °C. The aging enhances the adsorption of the crude’s polar components onto the rock surface, which is responsible for shifting the rock wettability toward more oil-wet conditions …”

Section: Experimental Workmentioning

confidence: 99%

Enhanced Oil Recovery in Carbonate Reservoirs Using Single Component Synthesized Surfactants under Harsh Reservoir Conditions

et al. 2023

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Surfactants are commonly used for enhanced oil recovery (EOR) applications in carbonate hydrocarbon reservoirs due to their ability to reduce oil/water interfacial tension (IFT) and/or alter rock wettability toward more water-wet conditions. They are usually used as formulations consisting of more than two surfactants to achieve optimum performance. Although this approach may result in extra recovery in coreflooding experiments, there is a risk of chromatographic separation and potential phase separation when these surfactants are injected into the reservoir. The current study, however, focuses on injecting a single component ethoxylated quaternary ammonium cationic Gemini surfactant (GS) or a betaine-type zwitterionic surfactant (ZIS), both synthesized in-house, to mitigate these potential issues. Several coreflooding experiments were conducted using Indiana limestone samples at 100 °C, pressures greater than 3000 psi, and seawater and formation water salinities of 57,745 ppm and 213,768, respectively. Continuous injection of either surfactant solution (at 2500 ppm in seawater) after seawater flooding recovered almost 11−12% of the initial oil in the core (OOIP). The results demonstrate that the GS or the ZIS alone can achieve this relatively high oil recovery without the need for additional cosolvent(s) or cosurfactant(s), unlike most of the previously developed surfactant formulations. Injecting a one-pore-volume slug of a standard acrylamide copolymer at 2000 ppm between the seawater and the surfactant floods increased the oil recovery by either surfactant to around 16−17% OOIP. This improvement in oil recovery was mainly due to wettability alteration from oil-wet to intermediate-wet conditions, as revealed by the contact angle and oil/water IFT measurements. Effluent analysis of the produced aqueous phase showed surfactant dynamic retention values of 0.44 and 0.61 mg/g-rock of both the GS and the ZIS, respectively. Such high oil recovery and low dynamic retention reflect the high efficiency of the GS and the ZIS for EOR applications in carbonate reservoirs.

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The Effect of Wettability on Waterflood Oil Recovery in Carbonate Rock Samples: A Systematic Multi-scale Experimental Investigation

Cited by 22 publications

References 68 publications

Synergistic Effects of Aqueous Phase Viscoelasticity and Reduced Interfacial Tension on Nonwetting Phase Displacement Efficiency: An In Situ Experimental Investigation

Synergistic Effects of Aqueous Phase Viscoelasticity and Reduced Interfacial Tension on Nonwetting Phase Displacement Efficiency: An In Situ Experimental Investigation

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

Enhanced Oil Recovery in Carbonate Reservoirs Using Single Component Synthesized Surfactants under Harsh Reservoir Conditions

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