Waterflooding In Reservoirs Research Articles

Microscopic Remaining Oil Initiation Mechanism and Formation Damage of CO <sub>2</sub> Injection after Waterflooding in Deep Reservoirs

Microscopic Remaining Oil Initiation Mechanism and Formation Damage of CO <sub>2</sub> Injection after Waterflooding in Deep Reservoirs

Reservoir Development by Waterflooding and Reservoir Performance Analysis

With the rapid development of China's society and economy, relevant industries get good development opportunities, and the demand for oil is increasing. The oil production in the oilfield is increasing day by day. At present, most oilfields gradually enter the middle and late stage of water injection exploitation, which increases the exploitation difficulty and reduces the exploitation amount. In this paper, a comprehensive analysis of waterflooding reservoirs and reservoir performance is made to promote better and faster development of petroleum industry.

Study of the efficiency of trapped gas displacement by non-hydrocarbon gases from water-flooded gas condensate reservoirs

Analyzing industrial data and the results of theoretical studies, it was found that the natural gas recovery factor in water-drive gas reservoirs is about 50-60%. Considering the significant volumes of residual gas reserves trapped by formation water, there is a need to improve existing development technologies and search for optimal ways to increase hydrocarbon recovery under conditions of intensive water encroaching. Additional researches using hydrodynamic simulations were conducted in order to study the efficiency of enhanced recovery of residual gas reserves by injecting non-hydrocarbon gases into productive reservoirs. Based on the 3D reservoir model, the study of carbon dioxide and nitrogen injection into the initial gas-water contact was carried out in order to slow down the breakthrough of formation water into productive reservoir. The study was performed for different injection duration of carbon dioxide and nitrogen into productive reservoir. According to the results of the statistical processing of the calculated data, the optimal duration of the nitrogen injection was determined to be 8,04 months. The ultimate gas recovery factor for the optimal period of nitrogen injection is 58,11%. At the time of the carbon dioxide breakthrough into production wells, the optimal duration of the carbon dioxide injection was determined to be 16,32 months. The ultimate gas recovery factor for the optimal period of carbon dioxide injection is 61,98 %. Based on a comparative analysis of the efficiency of using various types of non-hydrocarbon gases as injection agents into productive reservoirs, the high efficiency of using carbon dioxide for injection into the initial gas-water contact was established. Due to the solubility of carbon dioxide in formation water, the ultimate gas recovery factor is significantly higher compared to using nitrogen as an injection agent.

Visualization of water channeling and displacement diversion by polymer gel treatment in 3D printed heterogeneous porous media

Polymer gels are widely applied to increase the sweep efficiency in mature oil fields facing severe water channeling problems after years of water flooding. The formation of water channeling and successful polymer gel treatment are rooted in complex pore-scale displacement and diversion. Thus, accurate characterization of the pore space and direct visualization of the interior displacement processes in real reservoir rocks such as water flooding, polymer gel injection, and chase floods are crucial in determining the controlling mechanisms of water channeling and polymer gel diversion. In this study, 3D X-ray micro-computed tomography (μCT) was used to characterize the porous structures of three distinct levels in water-flooded reservoir sandstones. A heterogeneous digital model was designed, which comprised representative layers of the obtained porous structures. Then, 3D-printing technology was used to manufacture a transparent model based on the digital prototype. A series of displacement experiments were conducted in the printed model to directly visualize the flow behaviors in the actual pore geometries. In the experiments, the model was first saturated with white oil and flooded by formation water until the outlet discharged only the water phase. Then, an immediately prepared polymer gel was injected. After three days of gelation, an antidilution polymer was injected to sweep the residual oil in the model. Finally, a surfactant flooding agent was injected designed to further increase the oil recovery. The entire four-step displacement process was directly visualized, and the saturation of each injection and the oil recovery were calculated. During water flooding, preferential flooding channels formed in the highest water-flooded porous layers due to the low viscosity ratio between the injected formation water and the displaced white oil, as well as the permeability contrast in the heterogeneous model. The injected polymer gel mainly followed the preferential flooding channels because of the low resistance force in these channels. After gelation, the polymer gel blocked the main preferential channels and diverted the chase floods to nearby pores. A desirable diversion of the polymer gel highly depends on its propagation path during injection and effective blocking after gelation. Experimental visualization and displacement mechanism analysis indicate the efficacy of the flow diversion by the polymer gel treatment in the heterogeneous porous model. The results provide useful information on the displacement behavior in heterogeneous porous structures, and the conclusions apply to similarly scaled systems at the reservoir scale.

Adaptability Evaluation of Nitrogen Foam Flooding After Water-Flooding in Low-Permeability Light Oil Reservoirs

Adaptability Evaluation of Nitrogen Foam Flooding After Water-Flooding in Low-Permeability Light Oil Reservoirs

Isolating the effect of asphaltene content on enhanced oil recovery during low salinity water flooding of carbonate reservoirs

ABSTRACT Polar compounds in oil, especially asphaltene and resin, have important implications on the oil recovery from carbonate reservoirs; yet their isolated effects, independent of other oil properties, are not well understood. Thus, two different crude oils with similar densities and resin contents, but with dissimilar asphaltene contents, were selected to better understand asphaltene’s effect on: wettability alternations upon water injection, IFT changes, and areal sweep efficiency. It was found that crude oil with greater amount of asphaltene hinders the wettability alteration by undiluted and diluted seawaters, due to sustained hydrophobicity caused by polar compounds adsorbing onto the rock surface. Conversely, crude oil with lower amount of asphaltene, combined with low salinity waters, resulted in pronounced wettability alteration. Based on image analysis of the surface of carbonate rocks, higher areal sweep efficiencies were obtained for non-asphaltenic crude oil (around 35%, versus 6% to 30% for asphaltenic crude oil), using seawaters diluted ten-and fifty-fold, corresponding to the lowest contact angle values measured (36° and 22°, respectively). Asphaltene is thus deemed to play a key role in the wettability alteration of carbonate rocks, consequently affecting the performance of enhanced oil recovery during low salinity water injection.

Rastlantısal Parçacık Hareket Yöntemiyle İncelenen Dağılım Katsayısının Polimer Enjeksiyonu Üzerine Etkisi

Polymer injection is a chemical EOR process, where the aim is to improve sweep efficiency of water flooding in an oil reservoir by increasing the water viscosity with the thickening effect of polymer injected with water. A random walk particle tracking model is developed to simulate the injection of polymer into an oil reservoir and it is integrated into an open source black-oil reservoir simulator (SINTEF’s MATLAB Reservoir Simulation Toolbox, MRST). The black-oil simulator solves the set of partial differential equations describing multiphase fluid flow in the porous medium, whereas the transport of the injected polymer due to advection and dispersion processes is obtained from the applied random walk method. The finite difference/finite volume discretizations of the continuity equations applied in MRST does not involve the physical dispersion processes. The dispersion observed on the results are called the numerical dispersion and are due to the numerical discretization methods applied to solve the continuity equations. Since dispersion in porous media is a scale dependent process, it is hard to quantify its coefficient by experiments or empirical equations in general. The random walk method to model the transport of injected polymer in the reservoir is independent of discretization. Hence, it does not involve numerical dispersion. Instead, the physical dispersion due to, for instance, the tortuosity of flow path or the adsorption of polymer in porous media can be included into the model. Therefore, we used the method to analyze the effect of dispersion coefficient. Increased dispersion coefficient causes the results to converge to actual MRST solution with increased uncertainties of polymer concentration. The dispersivity of a reservoir in simple one-dimensional problems can be determined with the method.

A New Methodology of Production Performance Prediction for Strong Edge-Water Reservoir

Abstract Material balance is a basic principle in reservoir engineering, which is still used as a quick and easy analytical tool for reservoir evaluation. In this article, a new methodology of production performance prediction for water-flooding reservoir was proposed based on the material balance principle, which considers the water saturation change caused by water injection and natural water influx, and its effect on transient gas–oil ratio. Among them, the cumulative water production was calculated based on Tong’s water-driver performance curve; the cumulative water influx was obtained by the Fetkovitch method; the transient gas–oil ratio can be acquired by Darcy’s law and Baker’s relative permeability model. Comparisons have been made between the new methodology and commercial reservoir simulator for two different reservoirs. The results show that there is good similarity between these two tools, which verifies the correctness of the new methodology.

Experimental study on EOR potential of water-in-oil emulsion via CO2/N2 triggered wormlike micelle solution

Oil in water (O/W) emulsion flooding appears to be an effective method to boost oil production of mature oilfields, while few works have been done to investigate the enhanced oil recovery (EOR) potential of water in oil (W/O) emulsion, especially in in-situ W/O emulsion. In the present work, a CO2/N2 triggered wormlike micelle solution (CO2-TWMS) for forming in-situ W/O emulsion was prepared firstly. Then, its CO2/N2 responsiveness was characterized through the change in viscosity and microstructure. Subsequently, the emulsifying ability of CO2-TWMS and the effect of CO2/N2 responsiveness on emulsion stability were investigated, followed by the study of oil displacement efficiency. Experimental results manifested that CO2 bubbling triggered the formation of wormlike micelles, which induced the formation of W/O or O/W/O emulsion under stirring condition. While N2 bubbling destroyed wormlike micelles and accelerated the breaking of emulsion. 0.5 pore volume (PV) CO2-TWMS flooding and sequent water flooding could significantly improve oil recovery of 20.7–31.9% in three-floor heterogeneous cores, which was mainly contributed to the enlargement in sweeping efficiency that caused by mobility ratio improvement of emulsion and Jamin effect of water droplets. The results from this study demonstrated that the CO2-TWMS has great potential for EOR in waterflooded heterogeneous reservoirs, which provides valuable insights for novel EOR technology that combined chemical flooding with CO2 capture.

Implications of hot chemical–thermal enhanced oil recovery technique after water flooding in shale reservoirs

Due to the applicability of hot water injection in the heavy oil production, it has considered as one of the efficient methods in recovery performances. However, its low viscosity has caused to produce lower oil in shale formations. Therefore, hybrid chemical enhanced oil recovery techniques such as foam injection with sequential carbon dioxide injection would be of important in the heavy oil production. In this paper, we aimed to consider induced hot carbon dioxide–foam enhanced oil recovery technique after water flooding at different temperatures. First, we investigated temperature impact on the resistance factor at different gas–oil ratios (henceforth; GOR). Then, polyacrylamide additive (PAM) at different concentrations were added to the foaming agent to increase the foam stability. Oil recovery factor and water cut were measured for each scenario. According to the results of these experiments, temperature increase would cause to resistance factor increase in which the temperature of 180 °C has the highest resistance factor. It is about 93%. Moreover, increase of GORs has caused to enhance the resistance factor. Polymer concentration increase has caused to resistance factor increase that is related to the polymer property to enhance the foam stabilization. Consequently, by the increase of temperature, water changes from liquid phase to gas or vapor and this is why it has decreased in the first steps of pore volume injection. Therefore, in the temperature of 180 °C, there is not any water cut in the first period of injection. Furthermore, higher polymer concentration would have an important role on the oil recovery increase.

Imbibition into Capillaries with Irregular Cross Sections: A Modified Imbibition Equation for Both Liquid–Gas and Liquid–Liquid Systems

Due to discrepancies observed between many experimental results and predictions from the Bell–Cameron–Lucas–Washburn (BCLW) imbibition equation, the BCLW equation was often modified by considering the effects of pore/throat characteristics. As previous works mainly focused on liquid–gas systems, the effects of the viscosity ratios are neglected. In this study, the nonwetting-/wetting-phase-viscosity ratio ( $$ \Psi $$ ) is varied by four orders of magnitude (0.018 to 8), which covers the common fluid viscosity in waterflooded tight reservoirs. Capillaries with irregular cross sections (namely, complex capillaries), which are recognized to more representative for porous media, are used to theoretically study imbibition kinetics in both the liquid–gas and liquid–liquid system. To considering the effects of viscosity ratio, we propose a modified imbibition equation based on the Poiseuille law and a piecewise method to calculate the equivalent radius for complex capillaries. The predictivity of the new imbibition equation is mathematically validated in varying viscosity ratios and geometries characteristics (such as the radius levels and the numbers/length ratios of radius levels). The study proves that an equivalent straight capillary can globally predict imbibition behaviors in complex capillaries. Except for a few scenarios, the equivalent radius of the straight capillary is affected by capillary geometries and viscosity ratios. Only in the early stage of imbibition ( $$ l_{x} /l \le 0.12\Psi /\left( {\Psi - 1} \right) $$ ), the modified imbibition equation can be expressed as a power-law relation (i.e., $$ l_{x} /l \propto \frac{1}{\Psi }t^{\alpha } $$ ) as $$ {\Psi } $$ is higher than 1. In general, it is more suitable to express the imbibition equations in a quadratic form, especially for liquid–liquid imbibition systems.

КОМПЛЕКСНЫЙ ПОДХОД К ПРИМЕНЕНИЮ МЕТОДОВ АНАЛИЗА ЭФФЕКТИВНОСТИ СИСТЕМЫ ЗАВОДНЕНИЯ НЕФТЯНЫХ ПЛАСТОВ

Актуальность исследования обусловлена необходимостью обобщения накопленного опыта и информации по применению общепринятых методов анализа эффективности системы поддержания пластового давления, выявления достоинств и недостатков каждого отдельного метода и формирования рекомендаций по упрощению процесса проведения анализа эффективности при одновременном увеличении глубины и качества анализа, в перспективе обеспечивающих сокращение потерь добычи нефти. Целью исследования является формирование рекомендаций по совершенствованию процесса анализа эффективности системы заводнения нефтяных пластов на месторождениях, находящихся на поздних стадиях разработки. Объект: южная лицензионная территория Приобского месторождения (Ханты-Мансийский автономный округ). Методы: сравнительный анализ существующих методов оценки эффективности систем заводнения нефтяных пластов, выявление достоинств и недостатков, формирование комплексного подхода к применению методов анализа эффективности системы заводнения, оценка перспективности применения результатов исследования. Результаты. Рассмотрена методика оптимизации процесса анализа эффективности системы заводнения нефтяных месторождений путём разделения их на более мелкие гидродинамически замкнутые участки пласта – блоки (ячейки заводнения). Для повышения качества проводимого анализа предложен переход от реактивного подхода диагностики потерь к проактивному подходу, позволяющему предсказать и предотвратить снижение добычи нефти. На основании тенденции к укрупнению участков пласта, подлежащих анализу, по сравнению с традиционными методами анализа, и внедрения проактивного подхода предложен алгоритм повышения эффективности управления базовой добычей – проактивный блочно-факторный анализ. Рассмотрена перспективность применения результатов блочно-факторного анализа на примере одного из блоков Приобского месторождения (Ханты-Мансийский автономный округ). Возможно применение представленного алгоритма анализа для схожих геолого-физических условий других пластов с целью адаптации данной технологии на территории других месторождений.

Model-based water-flooding optimization using multi-objective approach for efficient reservoir management

The efficient development of an oil field mostly depends on a comprehensive optimization of subsurface flow. To account for several discrete or even contradicting objectives, multi-objective optimization (MOO) approach presents multiple optimum solutions for decision-making processes. There are excessive degrees of freedom in any optimization problem of the life-cycle of water-flooding to optimize the short-term performance during the process. Choosing each strategy has a different impact on the long-term reservoir performance. Thus, in this study, we have utilized two different model-based algorithms based on multi-objective particle swarm optimization (MOPSO) and non-dominated sorting genetic algorithm II (NSGA-II) methods with some modifications to plan the short- and long-term production strategies simultaneously in water-flooded reservoirs. These algorithms are both population-based techniques, in which the Pareto-ranking approach is combined with the inherent search towards the optimal solution for a multi-criterion optimization problem. Maximizing the long-term Net Present Value (LNPV) and short-term (discounted) NPV (SNPV) are the objectives to be met in the investigated MOO problems. To address the imperfect Pareto front obtained in MOO problems, some modifications have been added to the utilized algorithms, including using a modified comparison operator in the NSGA-II method and employing the crowding distance parameter in the leader selection process together with a revised archive controller as well as a dynamic boundary search to MOPSO algorithm. By these means, the entire Pareto fronts are actively generated, which covers the complete solutions area through both algorithms. To validate the developed approaches, two benchmark water-flooded reservoir models have been employed. In the first case, the optimization parameters are the wells injection rates in the Egg benchmark reservoir model. In the second one, we have adjusted the opening values of the inflow control valves (ICV) of smart wells in the water-flooding process of a layered reservoir with a five-spot pattern. The effect of the trading-off between Pareto elitism and diversity on the final results is investigated for both algorithms. Results illustrate that the competitive values of the NPV functions, LNPV and SNPV pairs, lying on the obtained Pareto front, provide a promising criterion to improve the decision-making process. A comparison of various methods shows that for both case-studies, MOPSO can strongly propose a production strategy that more appropriately optimizes SNPV and LNPV compared to the NSGA-II as well as compared to some previous efforts published in the literature. A high rate of convergence, together with the logical Pareto front having enough diversity and uniformity, and also the independency of the final solution on the initial guess, are the main advantages of MOPSO in comparison with other approaches.

Inter-well interferences and their influencing factors during water flooding in fractured-vuggy carbonate reservoirs

Abstract Based on the characteristics of injection-production units in fractured-vuggy carbonate reservoirs, nine groups of experiments were designed and performed to analyze the interference characteristics and their influencing factors during water flooding. Based on percolation theory, an inversion model for simulating waterflooding interferences was proposed to study the influence laws of different factors on interference characteristics. The results show that well spacing, permeability ratio, cave size, and cave location all affect the interference characteristics of water flooding. When the cave is located in high permeability fractures, or in the small well spacing direction, or close to the producer in an injection-production unit, the effects of water flooding are much better. When the large cave is located in the high-permeability or small well spacing direction, the well in the direction with lower permeability or smaller well spacing will see water breakthrough earlier. When the cave is in the higher permeability direction and the reserves between the water injector and producer differ greatly, the conductivity differences in different injection-production directions are favorable for water flooding. When the injection-production well pattern is constructed or recombined, it's better to make the reserves of caves in different injection-production directions proportional to permeability, and inversely proportional to the well spacing. The well close to the cave should be a producer, and the well far from the cave should be an injector. Different ratios of cave reserves to fracture reserves correspond to different optimal well spacings and optimal permeability ratios. Moreover, both optimal well spacing and optimal permeability ratio increase as the ratio of cave reserves to fracture reserves increases.

Robust optimisation of water flooding using an experimental design-based surrogate model: A case study of a Niger-Delta oil reservoir

Reservoir simulations are often applied in oil field development to predict and optimise the performance of the production process and improve the decision-making process. This process is made complex by the need to account for uncertainties in the simulation model input parameters. The classical Markowitz optimisation model is an approach that can be applied for reservoir performance optimisation considering uncertainty. However, numerous full-physics simulations are required for the optimisation procedure to work. To overcome this challenge, we deploy a surrogate model of total oil production for the robust optimisation of waterflooding in a Niger-Delta reservoir. Using this approach, we reduce computational costs and consider four uncertain geological variables in a robust application of the optimisation routine. To adequately capture the uncertainties in the geological model, we apply 100 realisations of the reservoir model. In our presented case, we show that by applying a proxy model of the cumulative oil production in the study, the computational costs of the optimisation routines are significantly reduced. Overall, we perform more than 10000 proxy model evaluations requiring 4 days and saving 417 days of computation time which is required if full-physics simulations were applied in the optimisation routine. As a result, we can make decisions accounting for uncertainty and the potential implications for variation in the development and operation of the field.

Interpolating Qualitative Time-Lapse Seismic Interpretations

SummaryTime-lapse seismic surveys, even if repeated at different calendar intervals, can only capture snapshots of a reservoir’s state. To obtain continuous information from these surveys, we propose a method to interpolate qualitative time-lapse seismic interpretations. As inputs, we take the sequence of interpreted boundaries of an expanding time-lapse seismic anomaly. Our solution combines the fast-marching method (FMM) and the Pollock (1988)pathline-tracing algorithm to estimate the intermediate boundary positions at times between acquisitions. For validation, we use a synthetic data set representing the scenario of a waterflooded sandstone reservoir. The results confirm that, despite small localized discrepancies in shape, at each time, the estimated boundary positions are in close agreement with the truth case. When time-lapse anomalies result primarily from changes in water saturations, the estimated boundary-arrival times resemble the actual water-front-arrival times. Hence, combined with classical immiscible displacement theory, the estimated arrival times can support a practical, model-independent, quantitative estimation of water saturations in the reservoir.

Direct numerical simulation of the effects of fluid/fluid and fluid/rock interactions on the oil displacement by low salinity and high salinity water: Pore-scale occupancy and displacement mechanisms

Laboratory experiments have shown that performance of waterflooding in oil reservoirs could be significantly increased by lowering the ionic strength and/or manipulation of its composition, which is generally known as low salinity waterflooding (LSWF). The involved mechanisms in additional oil production can be generally categorized in two categories, fluid/fluid and fluid/rock interactions. The distribution of the phases and the involved displacement mechanisms would be strongly affected by the inter-relations between capillary and viscous forces. Although there have been recent advances in the simulation of the LSWF at core scale and beyond and some models are included in commercial core-scale/field-scale simulators, there are very few works that modelled and simulated this process at the pore scale. As a result the effects of wettability alteration and/or interfacial tension (IFT) change on the distribution of the phases at pore scale as well as dynamics of the displacement are not thoroughly investigated and not well understood, even in spite of many micromodel experiments. The aim of the present study is to investigate the fluids distribution, redistribution and dynamic of the displacement mechanisms at the true pore scale (inside a pore), by modelling both rock/fluid (dynamic contact angle) and fluid/fluid (dynamic oil/water IFT as well as diffusion between high salinity and low salinity water) interactions. Simulation results show that in addition to the fluid/rock interactions, fluid/fluid interactions are also important in the effectiveness of LSWF and shall be considered in simulation studies. This is especially true in the case of non-water-wet systems. Our simulations provide new physical insights into LSWF and the dynamics of two-phase flow under wettability alteration as well as IFT changes induced by the LSWF, which cannot be easily captured by laboratory experiments. The results are also used to better explain some of the observed discrepancies in larger scales such as micromodel or coreflood experiments.

Detecting pH and Ca2+ increase during low salinity waterflooding in carbonate reservoirs: Implications for wettability alteration process

Wettability alteration appears to be an important physiochemical process during low salinity waterflooding (LSWF) in carbonate reservoirs. However, the leading factor(s) behind wettability alteration remains unclear. In particular, the relative contribution of calcite dissolution induced pH and Ca2+ increase has not been explicitly quantified. We thus hypothesized that the pH increase plays a significant role in the wettability alteration, whereas the increase of Ca2+ plays a minor role. To test this hypothesis, we performed a geochemical study and examined the effects of salinity level on calcite dissolution and pH increase against the recovery factor profile obtained from the literature. The calcite dissolution was evaluated by equilibrating different brines with calcite. The equilibrated pH and brine compositions were then to be employed to quantify the Ca2+ increase and calculate surface species and electrostatic force between oil-brine-calcite interfaces.Our results show that low salinity water (LSW) indeed triggers calcite dissolution, which induces the pH increase from 1 to 2 units, whereas only causes less than 10% increase of Ca2+ concentration in the low salinity water. Surface complexation modelling implies that Ca2+ concentration variation may not lead to significant chemical surface species variation on calcite surfaces, but the pH increase would play an important role on oil-brine interfaces especially for the oils with high base component (-NH+). Moreover, geochemical modelling shows that at least 5 times dilution of the original brine is required to obtain a pH increase from 6.5–7.0 to 8.0–8.5, which seems to be essential for triggering the wettability alteration. We argue that high salinity formation brines with the low initial pH (5.5 to 6.5), high basic component oils, and at least five-time dilution could be the three key favourable elements to trigger the low salinity effect in carbonate reservoirs. This work provides a practical framework to screen potential carbonate reservoirs and predict LSWF performance.

Study on frequency optimization and mechanism of ultrasonic waves assisting water flooding in low-permeability reservoirs

Water flooding is one of widely used technique to improve oil recovery from conventional reservoirs, but its performance in low-permeability reservoirs is barely satisfactory. Besides adding chemical agents, ultrasonic wave is an effective and environmental-friendly strategy to assist in water flooding for enhanced oil recovery (EOR) in unconventional reservoirs. The acoustic frequency plays a dominating role in the EOR performance of ultrasonic wave and is usually optimized through a series of time-consuming laboratory experiments. Hence, this study proposes an unsupervised learning method to group low-permeability cores in terms of permeability, porosity and wettability. This grouping algorithm succeeds to classify the 100 natural cores adopted in this study into five categories and the water flooding experiment certificates the accuracy and reliability of the clustering results. It is proved that ultrasonic waves can further improve the oil recovery yielded by water-flooding, especially in the oil-wet and weakly water-wet low-permeability cores. Furthermore, we investigated the EOR mechanism of ultrasonic waves in the low-permeability reservoir via scanning electron microscope observation, infrared characterization, interfacial tension and oil viscosity measurement. Although ultrasonic waves cannot ameliorate the components of light oil as dramatically as those of heavy oil, such compound changes still contribute to the oil viscosity and oil-water interfacial tension reductions. More importantly, ultrasonic waves may modify the micromorphology of low-permeability cores and improve the pore connectivity.

Gradual or Instantaneous Wettability Alteration During Simulation of Low-Salinity Water Flooding in Carbonate Reservoirs

Injection of low-salinity water into carbonate reservoirs has gained attention as a viable and efficient enhanced oil recovery approach through wettability alteration as prevailing mechanism. However, modeling and implementation of wettability alteration during simulation of low-salinity water injection are challenging because of the complex ion interactions and chemical reactions in the brine and oil mixture as well as on the rock surface. It is noteworthy that wettability alteration is usually considered instantaneous in black oil simulation. The main purpose of this work was to put this assumption into perspective; thus, it aims at discerning under what circumstances the instantaneous wettability alteration approach is plausible during simulation of low-salinity water flooding. To answer this question, an approach was proposed to consider gradual wettability alteration during simulation of low-salinity water flooding and the results were compared with instantaneous wettability alteration method. The results show that the impacts of simultaneous increase in $${\text{SO}}_{4}^{2 - } ,{\text{Ca}}^{2 + }$$ concentrations and temperature cause the difference between gradual and instantaneous wettability alteration to be more noticeable at the early times of injection. Therefore, the results highlight that the impact of gradual consideration would be important at the early time of low-salinity water flooding process.