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.

Injection of chemicals into sandstones could lead to wettability alteration, where oil characteristics such as the TAN (Total Acid Number) may determine the wetting-state of the reservoir. By combining the spontaneous imbibition principle (Amott-Harvey method) and interfacial tension indexers’ evaluations, we propose a workflow and a comprehensive assessment to evaluate wettability alteration and IFT when injecting chemical EOR agents. The study focused on examining the effect of alkaline and polymer solutions (alone) and alkali-polymer. The evaluation focused on comparing the effects of chemical agent injection on wettability and IFT due to: core ageing (non-aged, water-wet and aged, neutral to oil-wet); brine composition (no divalent and with 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 restored oil-wet state. IFT experiments were compared for a duration of 300 minutes. Data was gathered from 48 Amott imbibition experiments with duplicates. IFT and baselines were defined in each case for brine, polymer and alkali on every set of experiments. When focusing on the TAN and aging effects it was observed that in all cases, the early time production is slower and final oil recovery is larger comparing to non-aged core plugs. This data confirms the change of rock surface wettability towards more oil-wet state after ageing and reverse wettability alteration due to chemical injection. Furthermore, application of alkali with high-TAN oil resulted in a low equilibrium IFT. In contrast, alkali alone fails to mobilize trapped low-TAN oil, but causes wettability alteration and neutral-wet state of the aged core plugs. Looking into brine composition, the presence of divalent ions promotes water-wetness of the non- aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between mineral surface and polar compound of the in-situ created surfactant, hence accelerating wettability alteration. Finally, concerning mineralogy effects, high clay content core plugs are more oil-wet even without ageing. After ageing, a strongly oil-wet behaviour is exhibited. Alkali-polymer is efficient in wettability alteration of oil-wet core plugs towards water-wet state. Three main points are addressed in the paper: A comprehensive methodology to evaluate wettability and IFT changes for different oil and mineralogy types is presentedIn particular, for alkali injection, substantial wettability change effects are observed.For high TAN number oils, wettability and IFT effects can be quantified using the methodology and applied for screening of chemical agents for various rock types.

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.

Contemporary traditional practice of 3D oil and gas reservoir modelling has severe drawback. Namely, the natural water flow is neglected. The main reason for this consist in complexity of combining two processes - the field development and natural water flow in the reservoir. This paper authors compared carefully four different approaches proposed by arabian and russian specialists for simulation of oil and gas reservoirs with tilted fluid contacts for using in software package of geological and hydrodynamic modeling. Advantages and disadvantages of the proposed approaches are revealed. Additionally, authors propose their own, the most realistic approach to taking into account the natural water flow for 3D simulation of oil and gas reservoirs with tilted fluid contacts and perfoming forecast calculations.

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.