Potential Benefits of Fluid Optimization for Combined Smart-Water and Polymer Flooding: Impact on Remaining Oil Saturation

Tahir, Muhammad; Hincapie, Rafael E.; Foedisch, Hendrik; Strobel, Gion-Joèl; Ganzer, Leonhard

doi:10.2118/196763-ms

Cited by 10 publications

(22 citation statements)

References 46 publications

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“…The contact angle values were measured over time intervals of 20 min, as shown in Figure 12 . As predicted based on our previous work [ 34 , 39 , 40 , 41 ], there was no change in the contact angle due to the strong hydrophilic characteristics of the porous media. However, the aging process altered the rock surface, which became hydrophobic, resulting in oil polar compounds attaching to the rock surface.…”

Section: Resultssupporting

confidence: 79%

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Arekhov¹,

Hincapie

Clemens

et al. 2020

Polymers

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The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

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Section: Resultssupporting

confidence: 79%

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Arekhov¹,

Hincapie

Clemens

et al. 2020

Polymers

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“…We previously demonstrated [ 19 , 20 ] that polymers diluted in spiked sulfate brine are sensitive to mechanical degradation. Hence, we consider a seemly high polymer concentration in order to be able to further characterize the polymer viscoelastic properties (based on sulfate).…”

Section: Resultsmentioning

confidence: 99%

“…Our previous study [ 19 ] provides a detailed description of contact angles for aged and unaged cores for wettability alteration. It is believed that this wettability alteration process also occurred three weeks after aging.…”

Section: Resultsmentioning

confidence: 99%

“…Among these active divalent ions (PDI), sulfate is the most effective ion [ 18 ]. We have previously proposed the mechanism of SO 4 −2 [ 19 , 20 , 21 , 22 , 23 ] for the wettability alteration in sandstone reservoirs. Similarly, from a fluid-fluid interaction point of view, sulfates can improve oil-brine interface resulting in oil phase snap-off suppression and increase the oil drop size [ 4 , 19 , 24 ].…”

Section: Introductionmentioning

confidence: 99%

“…We have previously proposed the mechanism of SO 4 −2 [ 19 , 20 , 21 , 22 , 23 ] for the wettability alteration in sandstone reservoirs. Similarly, from a fluid-fluid interaction point of view, sulfates can improve oil-brine interface resulting in oil phase snap-off suppression and increase the oil drop size [ 4 , 19 , 24 ]. Moreover, Mahzari and Sohrabi [ 25 ], Morin et al [ 26 ], Sohrabi et al [ 27 ] revealed that low salinity flooding produces more stable and viscoelastic surface at the oil-brine interface.…”

Section: Introductionmentioning

confidence: 99%

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Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection

et al. 2020

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The injection of sulfonated-modified water could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence, possible higher oil recovery in combination with polymer. Therefore, detailed experimental investigation and fluid-flow analysis into porous media are required to understand the possible recovery mechanisms taking place. This paper evaluates the potential influence of low-salt/sulfate-modified water injection in oil recovery using a cross-analyzed approach of coupled microfluidics data and core flooding experiments. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase micromodels and core floods experiments helped to define the behavior of different fluids. Overall, coupling microfluidics, with core flooding experiments, confirmed that fluid-fluid interfacial interaction and wettability alteration are both the key recovery mechanisms for modified-water/low-salt. Finally, a combination of sulfate-modified/low-salinity water, with polymer flood can lead to ~6% extra oil, compared to the combination of polymer flood with synthetic seawater (SSW). The results present an excellent way to make use of micromodels and core experiments as a supporting tool for EOR processes evaluations, assessing fluid-fluid and rock-fluid interactions.

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Smart Water–Polymer Hybrid Flooding in Heavy Oil Sandstone Reservoirs: A Detailed Review and Guidelines for Future Applications

Khosravi,

Chahardowli,

Simjoo

2024

Energy Fuels

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The application of smart water−polymer hybrid flooding in sandstone reservoirs has gained significant attention in recent years. This study provides a comprehensive review of the smart water−polymer flooding concept, including the underlying mechanisms, necessary conditions, and specific applications in heavy oil sandstone reservoirs. Screening criteria and required conditions for each method are investigated thoroughly to ensure the possibility of their synergy. The study also addresses smart water deficiency as a single Enhanced Oil Recovery (EOR) process for heavy oil heterogeneous sandstone reservoirs. The effectiveness of smart water−polymer hybrid flooding in terms of enhancing oil recovery mechanisms, various injection scenarios, economic profitability, and associated risks such as injectivity decline and viscosity loss is thoroughly examined and compared in different experimental and simulation studies. Based on the literature, it is concluded that wettability alteration and mobility control are the main controlling mechanisms. The synergistic effect of these mechanisms can lead to an increase in oil recovery equal to or higher than the summation of each method separately, with more effective results for heavy oil reservoirs. Notably, among the various injection scenarios explored, smart water injection followed by a tertiary smart water−polymer flood demonstrated the highest ultimate oil recovery. Despite numerous experimental studies on this subject, a series of controversial results have been observed concerning issues such as injectivity, polymer retention, and cation exchange between the polymer and aqueous phase. This indicates the necessity for more detailed investigations on this hybrid EOR method in the future. Simulation and optimization studies, particularly by applying proxy models such as artificial-intelligence-based methods, seem to have a high potential for further field study in this topic.

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Potential Benefits of Fluid Optimization for Combined Smart-Water and Polymer Flooding: Impact on Remaining Oil Saturation

Cited by 10 publications

References 46 publications

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection

Smart Water–Polymer Hybrid Flooding in Heavy Oil Sandstone Reservoirs: A Detailed Review and Guidelines for Future Applications

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