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

Abstract

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.

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

“…The iron oxides cover the mineral grains and cause the reddish color of the rock. Further information on the outcrops used in this work can be seen in our previous work [ 10 , 38 ].…”

“…The total observation time was 300 min for each measurement, providing 900 data points with a time interval of 20 s between readings. As reported by Arekhov et al [ 38 ], IFT data is considered as an indexer of the behavior rather than a final value, given that the measurements can be challenging in terms of reproducibility.…”

“…To evaluate the effects of nanoparticles combined with alkali on wettability changes and IFT, we followed a series of steps that are described below and serve as a structure for understanding the results: Fluid/rock selection and characterization: As a continuation of the work previously performed by some of the authors [ 9 , 10 , 38 ], we have selected two surface-modified silica nanomaterials (characterized by means of ζ potential) and Na 2 CO 3 alkali, two brines (differing in ion content), and two oils (differing in TAN). Outcrop rocks (differing in clay content) were selected/characterized by routine core analysis (RCA); Interfacial tension (IFT) measurements: IFT was measured as a function of time at 60 °C using a spinning drop tensiometer to define fluid–fluid interactions.…”

“…Fluid/rock selection and characterization: As a continuation of the work previously performed by some of the authors [ 9 , 10 , 38 ], we have selected two surface-modified silica nanomaterials (characterized by means of ζ potential) and Na 2 CO 3 alkali, two brines (differing in ion content), and two oils (differing in TAN). Outcrop rocks (differing in clay content) were selected/characterized by routine core analysis (RCA);…”

“…In previous work, we evaluated the nanomaterials alongside with alkali (Na 2 CO 3 ) and with polyacrylamide polymers as emulsion stabilizers [ 9 , 10 ]. This included the evaluation of possible effects of other nanoparticles, alkali, and polymer [ 9 , 10 ] or alkali polymer [ 38 , 39 ] on wettability, IFT, and phase behavior.…”