Spontaneous Imbibition as Indicator of Wettability Change During Polymer Flooding

Juárez-Morejón, Jose L.; Bertin, Henri; Omari, Abdelaziz; Hamon, Gérald; Cottin, Christophe; Bourdarot, Gilles; Morel, Danielle

doi:10.3997/2214-4609.201700334

Cited by 8 publications

(4 citation statements)

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“…The rapid increase in volume indicates that the presence of polymer in the pore space contributed to wettability being reversed from slightly oil-wet towards weakly water-wet conditions. Similar observations were previously made by other authors [12,15,25] but without comparing the results to a brine/oil baseline. Our thorough study shows oil spontaneous imbibition in all brine saturated cores during the first two Amott-Harvey cycles.…”

Section: Estimating Wettability Alterations From Spontaneous Imbibitionsupporting

confidence: 88%

“…The study, however, noted that retention was notably higher in the waterwet Berea compared to the Bentheimer core: which shows that the permeability, surface area and pore size distribution in the core material is also of importance when investigating polymer/rock interactions on the core scale. Juarez-Morejon et al [15] used spontaneous imbibition experiments to evaluate wettability alteration by hydrolyzed polyacrylamide (HPAM) polymer in intermediate-wet Bentheimer sandstone. Amott tests in brine and polymer solutions were performed and showed that polymer produced oil more efficiently by spontaneous imbibition than brine.…”

Section: Introductionmentioning

confidence: 99%

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A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging

et al. 2022

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Polymers have been used as viscosifying agents in enhanced oil recovery applications for decades, but their influence on rock surface wettability is rarely discussed relative to its importance: wettability largely controls fluid flow in porous media and changes in wettability may significantly influence subsequent system performance. This paper presents a two-part systematic investigation of wettability alteration during polymer injection into oil-wet limestone. The first part of the paper determines wettability and wetting stability on the core scale. The well-established Amott–Harvey method is used, and five full cycles performed with repeated spontaneous imbibition and forced displacements. Wettability alterations are measured in a polymer/oil system, to determine polymer influence on wettability, and evaluated towards simpler brine/oil and glycerol/oil systems, to determine reproducibility and uncertainty related to the method and fluid/rock system. Polymer injection into oil-wet limestone core plugs is shown to repeatedly and reproducibly reverse the core wettability towards water-wet. Wettability changed both quicker and towards stronger water-wet conditions with polymer solution as the aqueous phase compared to brine and glycerol. The second part of the paper attempts to explain the observed behavior; by utilizing in situ imaging by Positron Emission Tomography, an emerging imaging technology within the geosciences. High resolution imaging provides insight into fluid flow dynamics during water and polymer injections, identifying uneven displacement fronts and significant polymer adsorption.

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Section: Estimating Wettability Alterations From Spontaneous Imbibitionsupporting

confidence: 88%

Section: Introductionmentioning

confidence: 99%

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging

et al. 2022

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“…Wettability alteration is a complex synergistic process that could be the outcome of different mechanisms. Polymers, for instance, can alter the wettability by a reptation mechanism, which leads to detachment of trapped oil droplets [ 23 ]. Chengara et al [ 24 ] studied the utilization of NPs to detach an oil drop from a solid surface.…”

Section: Introductionmentioning

confidence: 99%

Wettability Changes Due to Nanomaterials and Alkali—A Proposed Formulation for EOR

et al. 2021

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We investigated the usage of two silica nanomaterials (surface-modified) and alkali in enhanced oil recovery through Amott spontaneous imbibition tests, interfacial tension (IFT) measurements, and phase behavior. We evaluated the wettability alteration induced by the synergy between nanomaterials and alkali. Moreover, numerical analysis of the results was carried out using inverse Bond number and capillary diffusion coefficient. Evaluations included the use of Berea and Keuper outcrop material, crude oil with different total acid numbers (TAN), and Na2CO3 as alkaline agent. Data showed that nanomaterials can reduce the IFT, with surface charge playing an important role in this process. In synergy with alkali, the use of nanomaterials led to low-stable IFT values. This effect was also seen in the phase behavior tests, where brine/oil systems with lower IFT exhibited better emulsification. Nanomaterials’ contribution to the phase behavior was mainly the stabilization of the emulsion middle phase. The influence of TAN number on the IFT and phase behavior was prominent especially when combined with alkali. Amott spontaneous imbibition resulted in additional oil recovery ranging from 4% to 50% above the baseline, which was confirmed by inverse Bond number analysis. High recoveries were achieved using alkali and nanomaterials; these values were attributed to wettability alteration that accelerated the imbibition kinetics as seen in capillary diffusion coefficient analysis.

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“…One of the most well-known and widely used methods to deduce or assess wettability is the Amott imbibition test, which is applied not only to sandstones but also carbonates [ 4 , 5 ]. Amott spontaneous imbibition tests have been widely used in the industry for wettability evaluation [ 6 ]. The imbibition process is governed by the capillary suction phenomenon which, in turn, is directly related to the wetting state of the system and the interfacial tension (IFT) between fluids [ 7 ].…”

Section: Introductionmentioning

confidence: 99%

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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Spontaneous Imbibition as Indicator of Wettability Change During Polymer Flooding

Cited by 8 publications

References 0 publications

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging

Wettability Changes Due to Nanomaterials and Alkali—A Proposed Formulation for EOR

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

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