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.

We have studied wettability alterations through imbibition/flooding and their synergy with interfacial tension (IFT) for alkalis, nanoparticles and polymers. Thus, the total acid number (TAN) of oil may determine the wetting-state of the reservoir and influence recovery and IFT. Data obtained demonstrate how the oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid–fluid and rock–fluid interactions. We used a laboratory evaluation workflow that combines complementary assessments such as spontaneous imbibition tests, IFT, contact angle measurements and selected core floods. The workflow evaluates wettability alteration, IFT changes and recovery when injecting alkalis, nanoparticles and polymers, or a combination of them. Dynamics and mechanisms of imbibition were tracked by analyzing the recovery change with the inverse bond number. Three sandstone types (outcrops) were used, which mainly differed in clay content and permeability. Oils with low and high TANs were used, the latter from the potential field pilot 16 TH reservoir in the Matzen field (Austria). We have investigated and identified some of the conditions leading to increases in recovery rates as well as ultimate recovery by the imbibition of alkali, nanoparticle and polymer aqueous phases. This study presents novel data on the synergy of IFT, contact angle Amott imbibition, and core floods for the chemical processes studied.

Even though the influence of wettability alteration on imbibition is well-documented, its synergy with Interfacial-Tension (IFT) for Alkali/Nanoparticles/Polymer flooding requires additional investigation. Particularly, when the oil Total Acid Number (TAN) may determine the wetting-state of the reservoir and influences IFT. Therefore, a laboratory evaluation workflow is presented that combines complementary assessments such as spontaneous imbibition tests, IFT and contact angles measurements. This workflow aims at evaluating wettability alteration and IFT changes when injecting Alkali, Nanoparticles and Polymers or a combination of them. Dynamics and mechanism of imbibition was tracked by analyzing the recovery change with the inverse Bond number. Three sandstone types (outcrops) were used that mainly differ in clay content and permeability. Oils with low and high-TAN were used, the latter from the potential field pilot 16TH reservoir in the Matzen field (Austria). We have identified the conditions leading to an increase of recovery rates as well as ultimate recovery by imbibition of Alkali/Nanoparticles/Polymer aqueous phases. Data obtained demonstrate how oil TAN number (low and high), chemical agent and reservoir mineralogy influence fluid-fluid and rock-fluid interactions. Application of alkali with high-TAN oil resulted in a low-equilibrium IFT. Alkali-alone fall short to mobilize trapped low-TAN oil. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state for high-TAN oil. The investigated nanofluids manage to restore a water-wet state in cores with high clay content along with improving gravity driven flow. IFT reduction between oil and surface-modified nanoparticles is unaffected by the acidity of the oil. Furthermore, contact angle in high-TAN oil remained similar even after 1000 min of observation for 2.5% clay cores in synthetic brine, but increases significantly when in contact with alkali/polymer. Comparing porosity and permeability before and after imbibition, a slight reduction was observed after imbibition with brine and nanofluids. We preliminary conclude that permeability reduction is not associated to the tested nanoparticles present in solution. We observed evidence of change in the imbibition mechanism from counter-current (capillary driven/high inverse Bond number) to co-current (gravity driven/low inverse Bond number) for nanoparticles/alkali. The calculated inverse Bond number correlates with the ultimate recovery, larger inverse Bond number leading to lower ultimate recovery. This work presents novel data on the synergy of IFT, contact angles and Amott imbibition for the chemical processes studied. We leverage from complementary laboratory techniques to define a comprehensive workflow that allows understanding wettability-alteration when injecting Alkali, Nanoparticles and Polymers or a combination of them. Obtained results show that the workflow can be used as an efficient screening tool to determine the effectiveness of various substances to increase oil recovery rate and ultimate recovery.

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