Efficient Enhanced Oil Recovery Research Articles

Synergistic collaborations between surfactant and polymer for in-situ emulsification and mobility control to enhance heavy oil recovery

Surfactant-polymer (SP) combined systems is an effective nonthermal method to enhance the heavy oil recovery, through in-situ emulsification and mobility control mechanisms. In this study, a novel SP system was developed using 0.2 wt% anionic surfactant (alkyl naphthol polyoxyethylene ether sulfonate, ANES) and 0.1 wt% polymer (partially hydrolyzed polyacrylamide, HPAM). The SP system had viscosity reduction rate of ∼ 98 %, viscosity ratio of oil to displaced water (μo/μd) of ∼ 3.95 and IFT of ∼ 0.29 mN/m, beneficial for decreasing the mobility ratio of water to heavy oil. Then, the applied performances including emulsion morphologies and stability, wettability alteration ability were systematically characterized. The results showed that the freshly O/W emulsions formed by SP system displayed uniform droplet size distribution, as well as high stability with tight interfacial film. In addition, the SP system exhibited excellent wettability alteration property with low contact angle of 18.3°. The synergistic collaboration mechanisms of surfactant and polymer include heavy oil–water interfacial tension reduction, in-situ emulsification, oil-viscosity reduction and water-viscosity increase. Finally, the static oil washing and dynamic sand-pack flooding experiments showed that the SP system exhibited high oil washing efficiency (62.89 %) and enhanced oil recovery efficiency (56.9 %) with improving the mobility controllability after the primary water-flooding process. This study indicated that the synergistic collaborations between surfactant and polymer had great potential to enhance the heavy oil recovery.

Performance evaluation of ferro-fluids flooding in enhanced oil recovery operations based on machine learning

The process of enhanced oil recovery (EOR) and core flooding involves various challenges such as preserving cores, configuring experiment setup, scaling from the laboratory to the field, interpreting experimental data, handling interactions between multiple EOR agents, and performing cost-effective evaluations. However, recent advancements in artificial intelligence and deep learning have facilitated the prediction of EOR efficiency, simplifying the process while saving time and money - two vital aspects of petroleum engineering. This study employed deep learning to determine the impact of ferro-fluids on EOR efficiency, which reduces excessive laboratory analysis costs and saves time. The findings may aid in optimizing injectable materials for future EOR projects. Four machine learning (ML) algorithms were utilized to predict the efficacy of ferro-fluids in carbonate and sandstone core flooding: support vector machine (SVM) for classification, multilayer perceptron (MLP), radial basis function (RBF), artificial neural network (ANN), and adaptive neuro-fuzzy inference system (ANFIS) for regression. The models were trained initially, followed by creating a set of validating measurements through classification to determine the regression trend of ferro-fluids. The SVM accurately classified all data points and the resulting regressions were satisfactory, with MLP and ANFIS producing R2 values of 0.9957 and 0.9922, respectively.

Synthesis of colloidal silica nanofluid and assessment of its impact on interfacial tension (IFT) and wettability for enhanced oil recovery (EOR)

Ever-increasing global energy demand, from one hand and reduced oil initially in place in oil reservoirs due to production and reduced natural reservoir production capacity, on the other hand, has encouraged researchers to investigate different methods to improve and increase enhanced oil recovery (EOR) from oil reservoirs. One method is to employ nanotechnology in injected water, where nanoparticles could affect interfacial tension (IFT) between water and oil and wettability through properties, including high specific surface area and nanoparticle size. However, a major challenge in using nanoparticles in injected water is the instability of these particles in water, which ultimately reduces the efficiency of EOR. These particles cannot be stabilized through conventional methods at a large scale. In this study, stabilized silica nanoparticles were synthesized in the water phase using sodium silicate and sol–gel processes. The stability of this nanofluid was studied in seawater, and then its effect on IFT and changing wettability was examined. According to the results, seawater containing 40 times diluted nanofluid could obtain 41% reduced IFT and 40% alteration in wettability of carbonate core becoming more water-wet and ultimately 13.7% improved final oil recovery in secondary oil recovery and 8.3% improved final oil recovery in third EOR.

Enhanced oil recovery through alternating gas Re-injection to reduce gas flaring in the Bakken

Environmental performance is a significant driver of energy production today, and providing attractive methods to reduce flaring remains a high priority for oil producers. The Energy & Environmental Research Center (EERC), with support from the Bakken Production Optimization Program (BPOP), is investigating the reinjection of the associated gas into producing wells to reduce flaring.The project's main objectives are to evaluate technically and economically the feasibility of deploying alternating gas re-injection in the Bakken formation as a means to increase oil recovery, reduce flaring and maintain compliance. The approach addresses the compression capacity constraints, mineral ownership types, and gas availability. Gas reinjection has the added benefit of producing incremental oil that can offset installation and operational costs associated with gas compression and nonproducing time for a well during injection. A flow simulation model is created to investigate alternating gas injection of a four-well pad and to assess the possibility of incremental oil production. Extensive numerical simulation is conducted. Capital expenditure, operating costs and the revenue from oil recovery were considered. Results indicate that gas injection within rates of 100–200 Mcfd can produce incremental oil. The gas volume needed is greater than what is typically flared from a facility, however, less than the total produced gas volume, and, therefore, possible. Communication of gas is likely to occur between wells within 1500 feet and wells positioned heel to heel that are common to the well-pad facility. The most promising injection period appeared to be within a 2-week to 1-month cycle. Thus, the proposed approach can be employed as an efficient Enhanced Oil Recovery (EOR) technique, alternating gas injection of 3 MMcfd may potentially increase the produced oil rate by 70 %. The findings support continued work to further investigate well configurations that can best benefit from the technique and to mature economic case studies.

A new approach based on VIKOR and Monte-Carlo algorithms for determining the most efficient enhanced oil recovery methods: EOR screening

Most of oil reservoirs in the world have faced decrease in production and they are in the second half of their life cycle. Therefore, tertiary and enhanced oil recovery (EOR) techniques are needed for continuous production from these reservoirs. As choosing the most appropriate EOR methods for a reservoir is a challenging task for reservoir engineers, screening of EOR approaches is of high importance before any full field simulation and experiments. Enhanced oil recovery screening is a multiple criteria decision-making (MCDM) problem and hence, a systematic statistical algorithm based on MCDM can be used for this purpose. In this study, for the first time, a new EOR screening method is proposed by using VIKOR and Monte-Carlo algorithms. The approach used a large database of successful EOR projects around the world and was applied to 12 various EOR methods including a wide range of conditions and properties. Pre-processing was performed on the gathered database and then based on reservoir engineering analyses and using a pairwise comparison matrix, initial weights were considered for the parameters in each EOR method. Afterward, these weights were used in the proposed VIKOR MCDM calculation algorithm and the corresponding numerical values of EOR techniques for each reservoir were obtained. Finally, the EOR method with the highest corresponding value was selected as the most suitable method. Results demonstrated that by using the presented approach, a high classification accuracy of 98% was obtained for different cases, which shows the proficiency and robustness of the developed screening algorithm. In addition, the reliability of the developed method was validated using data obtained from 11 oil reservoirs in the southwest of Iran. Also, the results were compared with the results of previous studies and they were in a very good match. The developed approach is less expensive and faster than full field simulation method and can be used as an efficient EOR screening approach for reservoirs with different properties in the world.

Reactive transport modeling of scale precipitation and deposition during incompatible water injection in carbonate reservoirs

Seawater injection is an efficient enhanced oil recovery (EOR) method that capitalizes on the chemical composition differences between the injecting seawater and in-situ formation water, which leads to physicochemical interactions between the rock and fluids. These rock and fluid interactions result in changes of rock wettability and subsequent improved microscopic sweep efficiency. However, the ion imbalance resulting from seawater injection and its incompatibility with the in-situ formation water may interfere with the rock and fluids equilibrium state, causing scale precipitation and subsequent deposition which can negatively impact rock quality, well productivity and reservoir performance. In this study, an accurate, robust, and general approach is presented by coupling a geochemical module with a compositional two-phase fluid flow model to handle reactive transport in porous media. The proposed coupled model, so-called ad-scale model, is capable of simulating carbonate rock dissolution and sulfate scale formation/deposition for evaluating reservoir performance under incompatible water injection. The model predictions were validated using experimental data. This model was also utilized to predict water injection rate into a carbonate formation. It was obtained that both the reacting and non-reacting component profiles were accurately predicted using the proposed coupled model. The water injection rate prediction was also validated and showed high accuracy with absolute error and coefficient of determination values of 9.02% and 0.99, respectively. In addition, a sensitivity analysis was performed on water composition, which showed a strong dependence of reservoir and well performance on water composition.Graphical abstractThis diagram elucidates what exactly happens during incompatible water injection in the mixing zones near the injection well (right half of the figure) or production well (left half of the figure) where most of the geochemical phenomena occur.

Wettability alteration and interfacial tension reduction on high salinity of anionic/nonionic surfactant

Surfactants are used in enhanced oil recovery (EOR) methods to decrease interfacial tension at the oil-aqueous interface and to alter the wettability of the reservoir rock. Herein, the effect of salinity on interfacial tension (IFT) reduction and wettability was investigated using a mixture of a nonionic and an anionic surfactant. Brines with varying salinities are being considered in this study. The interfacial property and rock wetting characteristics of the surfactant were examined by measuring the interfacial tension and contact angle (CA), respectively. The IFT at the oil-aqueous interface was shown to decrease considerably under high salinity. Furthermore, CA measurements revealed that a high salinity anionic/nonionic surfactant was successful in altering oil-wet sandstone to a water-wet condition. IFT and contact angle are interrelated to provide significant EOR efficiency. Thus, this anionic/nonionic surfactant provides good properties for EOR applications.

Enhanced Oil Recovery by Surfactant Injection was improved during the Last 50 Years Thanks to the Multivariable HLD Formulation Equation

This report reviews the progress in Enhanced Oil Recovery (EOR) through surfactant injection over the past half century from 1974, with a specific focus on the role of the multivariable Hydrophilic-Lipophilic Deviation (HLD) formulation equation in different expressions. This equation has been instrumental in optimizing surfactant formulations for EOR, enabling the fine-tuning of surfactant types and properties to match specific reservoir conditions like brine salinity, crude characteristic, temperature and even pressure. This short assesment discusses the evolution of surfactant types, and their impact on EOR efficiency for a given reservoir specifications. It highlights the role of intramolecular and intermolecular mixing in surfactant performance, and the benefits of using a multivariable HLD equation to predict and optimize the injected formulation. Furthermore, it explores the challenges and solutions related to surfactant adsorption, aggregation, precipitation, and effect on phase behavior and interfacial tension, and how these factors have to be considered when using surfactants for EOR projects. This review aims to address the existing gaps in the literature, such as the complex effects of surfactant mixtures with insensitivity to temperature and injected composition (amphiphilic concentration and water/oil ratio) that make difficult to propose a unified approach for different petroleum reservoirs. It concludes a discussion on the state of the art and future of surfactant EOR, emphasizing the need for continued research and collaboration across academic and industrial sectors

Investigation on the interactions of resinous and asphaltenic synthetic oils and silicon oxide nanoparticles stabilized by different ionic liquid-based surfactants: interfacial tension and wettability alteration studies

The effects of the main components of crude oil, especially resin and asphaltene fractions, are essential concerns for efficient enhanced oil recovery (EOR) processes, especially during chemical injection processes. This importance comes from the nature of these two fractions which can act as surface active agents with undeniable effects on the used chemical for interfacial tension (IFT) reduction and wettability alteration. In this way, the effect of silicon oxide nanoparticles (SiO2-NPs) concomitant with two ionic liquids (ILs), namely 1-dodecyl-3-methyl imidazolium chloride ([C12mim][Cl]) and 1-octadecyl-3-methyl imidazolium chloride ([C18mim][Cl]), is investigated on the wettability alteration and IFT reduction using synthetic oils prepared by dissolving the extracted resin and asphaltene fractions with a concentration of 1–5 wt%. The measurements reveal that the effect of resin fraction is less than the asphaltene fraction for IFT reduction and wettability alteration. The sole presence of resin fraction reduces the IFT from 35.3 to 28.3 mN/m as the concentration is increased from 1 to 5 wt%, while a similar increase in the asphaltene fraction concentration reduces the IFT from 35.5 to 19.1 mN/m. Besides, the results reveal that the presence of [C12mim][Cl] in the range of 0–1000 ppm leads to a reduction in IFT from its maximum value of 35.3 to 0.81 mN/m, while in the case of [C18mim][Cl] with similar concentration variation, IFT is reduced from 35.3 to 0.7 which means the better effect of IL with longer chain length on the IFT reduction. Further analysis revealed that the effect of asphaltene fraction on the IFT is higher than resin fraction since the minimum IFT value was observed for [C18mim][Cl] with the value of 0.58 mN/m, while the contact angle (CA) values revealed revers effect for asphaltene fraction compared with the resin fraction. In general, regardless of the used IL, it seems that ILs leading to better wettability conditions which are crucial for EOR purposes and even better IFT values that can mobilize the trapped oil toward production points. Besides, further measurements revealed a positive effect of SiO2-NPs concomitant with the ILs to move the wettability toward the strongly water-wet condition with CA values of 29.2° and 28.3° for SiO2-NPs concentration of 1000 ppm and 1000 ppm of concentration for [C12mim][Cl] and [C18mim][Cl], respectively, for resinous synthetic oil (RSO) (5 wt%) while no meaningful effect regarding the SiO2-NPs presence at the different concentrations (100–2000 ppm) is found on the IFT reduction. A similar trend is observed for asphaltenic synthetic oil (5 wt%)/aqueous solution (SiO2-NPs with a concentration of 1000 ppm + ILs with a concentration of 1000 ppm) which reduces the CA to 26.3° and 37.8° for [C12mim][Cl] and [C18mim][Cl]), respectively.

Experimental evaluation of the water-based enhanced oil recovery methods in ultra-tight reservoirs

Water-based enhanced oil recovery methods have been developed to improve the oil production rate from ultra-tight reservoirs. By coupling the effect of surfactant as wettability alteration and water alternating gas injection method, we aimed to determine the most efficient enhanced oil recovery technique. We performed seven injectivity scenarios to measure the oil recovery factor by introducing the alkylbenzene sulfonic acid (LABSA) as a surfactant agent during the active carbonated water alternating gas (ACWAG) injection. To consider the effect of slug size during water alternating gas injection, we used two different slug sizes (0.3, and 0.6). After the water breakthrough, a little oil volume was produced, and the maximum oil recovery factor at 1.5 Pore Volume (PV) was 26%. This issue corresponded to the water channeling after the breakthrough point. For smaller slug sizes (0.3), the maximum oil recovery factor (78%) was reached in smaller pore volumes. One of the exciting results wass the considerable influence of slug ratio during the water alternating gas (WAG) injection, in which it provided more oil recovery factor (83%) when the gas volume is higher than the water volume. Finally, by introducing the coupling effect of active carbonated water (made by LABSA surfactant) and WAG injection, the maximum oil recovery factor was 85%, corresponding to the better efficiency of active carbonated water in interfacial tension reduction. The results of this comprehensive investigation can be extended in ultra-tight sandstone reservoirs and can be applied as a further guideline in numerical simulations.Graphical abstract

Evaluation of enhanced oil recovery methods for mature continental heavy oil fields in China based on geology, technology and sustainability criteria

Enhanced oil recovery (EOR) methods in mature oil fields play an irreplaceable role in supporting the long-term and stable production of crude oil. This study establishes a unified and comparable evaluation index system based on geology, technology and sustainability, re-evaluates the existing EOR projects focused on heavy oil extraction by utilizing hybrid AHP-CRITIC-FCE models, and selects the most efficient, economic, and low-carbon footprint EOR technologies to facilitate the development of mature Chinese heavy oil fields. Three main criteria and nineteen subcriteria are considered in the multi-criteria decision-making system. The weights given to criteria are determined by combining the subjective AHP and objective CRITIC methods. The fuzzy comprehensive evaluation method is adopted to prioritize the performance of the EOR process. Empirical analysis is conducted on seven typical heavy oil technologies. The study finds that geological factors account for the largest proportion, and the top five indicators in terms of weight are buried depth, recovery factor, viscosity, operating cost per tonne of oil and reservoir thickness. Three technologies are recommended for potential future green footprint heavy oil EOR methods. This study combines both expert judgment and field data appraisal to help decision makers better plan the future strategic layout of EOR technology.

Effect of salinity on solution properties of a partially hydrolyzed polyacrylamide

The growing energy demand requires maximization of oil recovery from known reserves, while enhanced oil recovery (EOR) techniques are focused on sweeping residuals available in reservoirs previously flooded with water. Polymer additives are widely applied in EOR processes, as they can increase the viscosity and reduce the water permeability leading to mobility decrease of the injected solution. In this study, structural and rheological characterizations of a partially hydrolyzed polyacrylamide (FLOPAAM 3630S) were performed in a wide range of salinity relevant to conditions in existing oil reservoirs. Macromolecular solutions were identified at low polymer concentrations and/or at elevated salt levels, while gelation, i.e., formation of coherent structure, was observed at high FLOPAAM 3630S doses at low salinity. The transition points between these stages were determined and a comparison of scattering and rheology measurements revealed that the driving force of such a transformation is of non-electrostatic origin, but rather relies on the hydrophobic intermolecular interactions. The results bring new insights into the design of efficient EOR processes applied in oil reservoirs of different salt levels.

Three-dimensional core reconstruction and performance evaluation of CO2 displacement in a tight oil reservoir

In this study, a three-dimensional tight sandstone core was reconstructed digitally using serials thin sections cut from a core sample used in laboratory carbon dioxide (CO2) flooding experiments. Based on the digital core, multiphase flow simulations were carried out to evaluate the performance of three prior laboratory-tested injection strategies: CO2 continuous injection, water alternative gas (WAG: CO2) injection, and cyclic CO2 injection. The chosen image-based reconstruction led to a close porosity and permeability match with the sampled core in an economical way. The numerical evaluation closely replicated the laboratory-tested procedures, thus providing realistic fluid distributions before CO2 injection. To determine saturation functions for CO2 injection after water flooding, sensitivities of endpoint relative permeability and capillary pressure to CO2 continuous injection were quantified. Water relative permeability was identified as a key factor. The saturation functions were used in a history match between simulations and laboratory data where close agreements were observed for all three CO2 injection strategies. Then critical enhanced oil recovery (EOR) operational parameters (soaking time, slug ratio, cycle size, and test duration) were optimized to maximize CO2 displacement performance, which led to the following observations: (1) While extended soaking after CO2 continuous injection increased incremental oil recovery, such increase was limited due to concurrent soaking during low-rate CO2 injection. (2) In WAG injection, CO2 and brine slug sizes and ratios were optimized: increasing the cycle size performed better than adjusting the slug ratio for favorable mobility control and efficient CO2 EOR. (3) For cyclic CO2 injection, the total CO2 injection volume was the most important factor, followed by the number of cycles, to allow CO2 diffusion into tight core to maximize the swept pore volumes. The history-matched simulations suggest that both WAG and cyclic CO2 injection can achieve high displacement effectiveness for the tight reservoir, compared with that achieved with slight soaking after CO2 continuous injection. The injected brine slugs in the WAG injection reduced the CO2 needed at the expense of reduced storage capacity. Compared to WAG, cyclic CO2 injection, though realizing the highest oil recovery and gas storage, requires more CO2.

An experimental approach to investigate oil recovery during ion-tuned water injection: A new insight into the asphaltene effect

Regarding the increase of the worldwide demand for supplying fuel, Enhanced Oil Recovery (EOR) methods, as promising methods for increasing oil recover factor, is a vital issue. The smart water injection is a well-accepted as an environmentally friendly, inexpensive, and efficient EOR method. This research aims to investigate the effect of oil and asphaltene chemistry on the sensitivity of oil production toward ion-tuned water. In this regard, three oil samples of crude oil, deasphaltened oil, and asphaltene-rich toluene were employed, as well as various brine samples containing different salinity values and ion types. The provided oil samples were characterized using Fourier-transform infrared spectroscopy (FTIR) and elemental analysis. The interfacial tension (IFT) values between the prepared water and oil samples of crude oil, deasphaltened oil, and asphaltene-rich toluene was in the ranges of 7.5–11, 14–23, and 12–19 m.N/m, respectively. Regarding higher IFT between the sulfate-rich water and asphaltene-rich oil, it was shown that the asphaltene molecules have a lower affinity toward the sulfate ions. In contrast, enriching the seawater with magnesium and calcium ions led to a tense IFT reduction. Regarding the contact angle measurements, the wettability of the sections, which were aged by the asphaltene-rich toluene, was respectively less sensitive to the ion-tuned waters compared with those aged by deasphaltened oil. For instance, because of the seawater treatment, the contact angles of the sections lie in the ranges of 48–87, 45–83, and 56–98° for sections aged by crude oil, deasphaltened oil, and asphaltene-rich toluene, respectively. More feasibility of the calcium and magnesium for desorption of the hydrocarbons was also observed in the zeta potential tests. The overall effects of rock-fluid and fluid-fluid interactions were observed in the imbibition tests. While the production from the crude oil saturated due to imbibition of the magnesium and calcium was noticeable, lower production was observed due to the sulfate-rich water imbibition into the asphaltenic oil sample. The experimental approach in this study could be a benchmark to screen the suitable reservoir oil for water injection.

Effect of modification degrees on the interfacial properties and EOR efficiency of amphiphilic Janus graphene oxide

Asymmetrically modified Janus graphene oxide (JGO) has attracted great attention due to its unique physical chemistry properties and wide applications. The modification degree of Janus nanosheets inevitably affects their interfacial activity, which is essential for their performances in enhanced oil recovery (EOR). In this study, the interfacial properties of Janus graphene oxide (JGO) with various modification degrees at liquid-liquid and liquid-solid interfaces were systematically evaluated via the measurements of interfacial tension (IFT), dilatational modulus, contact angle, and EOR efficiency was further assessed by core flooding tests. It is found that JGO-5 with higher modification degree exhibits the greater ability to reduce IFT (15.16 mN/m) and dilatational modulus (26 mN/m). Furthermore, JGO can construct interfacial and climbing film with the assistance of hydrodynamic power to effectively detach the oil from the rock surface and greatly enhance oil recovery. Moderately modified JGO-2 can highly improve recovery of residual crude oil (11.53%), which is regarded as the promising EOR agent in practical application. The present study firstly focuses on the effects of modification degrees on the JGO interfacial properties and proposes diverse EOR mechanisms for JGO with different modification degrees.

Experimental investigation on the enhanced oil recovery efficiency of polymeric surfactant: Matching relationship with core and emulsification ability

The polymeric surfactant can be used as an efficient agent for enhanced oil recovery (EOR) because of its large bulk viscosity and good interfacial activity. However, there is a sparse understanding of its matching relationship with reservoirs and emulsification occurrence conditions, which may affect its migration and EOR efficiency. One intermolecular association molecule polymeric surfactant (IAM) was synthesized by micellar polymerization and characterized with 1H NMR, FTIR, and TGA. The matching relationship between IAM and reservoirs was evaluated by comparing the viscosity retention rate of effluent in the core flow experiments. Moreover, the effect of the matching relationship on EOR in the heterogeneous reservoir was clarified with parallel core displacement experiments by considering different flow abilities of IAM in the high-permeability layer. The occurrence conditions of in-situ emulsification of IAM were evaluated via oil-water co-injection experiments under the different injection rates and oil-water ratios. Microscopic visualization displacement was carried out to compare the micro EOR mechanisms of different chemical systems. The results show that IAM features thickening, shearing resistance, viscoelasticity, thermal stability, and interfacial activity. The matching relationship between cores and IAM could be divided as hardly injected, flow limited, and flow smoothly, corresponding to the viscosity retention ratio of <20%, 20%–80%, and >80%, respectively. IAM could gain better EOR efficiency (17.69%) when its matching relationship to the high permeability layer was “flow limited”. The defined mixture capillary number shows that only when it is greater than 1 × 10−3, the in-situ emulsions can be generated. Compared to HPAM, IAM could reduce IFT and form vortices to more effectively displace film and corner remaining oils by stripping and peeling off crude oil. The formed emulsion accumulated at the pore throat could further increase flow resistance, which benefits swept area enlargement. This work could provide theoretical and data support for the parameters design in the polymeric surfactant practical application.

Countercurrent imbibition in low-permeability porous media: Non-diffusive behavior and implications in tight oil recovery

Countercurrent imbibition is an important mechanism for tight oil recovery, that is, water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture. Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces. We used the computed tomography (CT) scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance (CID) at different fluid pressures, initial water saturations, and permeability. Surprisingly, experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule (i.e., evolutes proportional to square root of time, t 0.5 ). At early stage, CID extends faster than t 0.5 (super-diffusive); while at late stage, CID extends much slower than t 0.5 (sub-diffusive). After tens of hours, the CID change becomes too slow to be practically efficient for tight oil recovery. This research demonstrates that this deviation from classic theory is a result of (1) a much longer characteristic capillary length than effective invasion depth, which eliminates full development of a classical displacement front; and (2) non-zero flow at low water saturation, which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks. To well depict the details of the imbibition front in this situation, we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations, which successfully rationalizes the non-diffusive behavior and fits experimental data. Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition, beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery (EOR) strategy than soaking for longer time.

Technology Focus: EOR Modeling (January 2023)

The oil and gas industry is facing unprecedented responsibility and expectations to keep fueling the world’s economies and social developments with reliable, accessible, safe, and affordable energy sources while responding to the global urgency to safeguard natural resources and protect the environment. Most major oil and gas companies have announced decarbonization strategies for low-carbon or net-zero emissions associated with their business operations. Consequently, reducing the carbon intensity of oil production [kilograms of carbon dioxide (CO2) equivalent emitted per produced barrel of oil] will be pivotal to meeting the environmental mandate. On the other hand, approximately 70% of the world’s counties have set targets to reach net zero within the next 3–5 decades, including emissions from burned hydrocarbon, which is a major challenge. Within this exigent mission to transition the industry, a major question arises about the merit and the role of enhanced oil recovery (EOR). With a share below 3% of the global oil production, field-scale EOR deployment and contribution have been modest despite substantial investments made in research and development and piloting in the last 4 decades. This underperformance of EOR has been attributed mostly to competitive alternatives (waterflooding), high cost, complex infrastructure and supply chains, fluctuating oil prices, and others. In the era of thirst for sustainability in our industry, there are reviving opportunities for selective EOR methods that can achieve efficient oil production with low carbon intensity. For instance, CO2 EOR is intuitively a win/win technology. This method may not be feasible everywhere for various reasons, however, including the availability and proximity of CO2 sources and the suitability of reservoir conditions. Chemical EOR methods, such as low-salinity, polymer-, and surfactant-based methods with low chemical usages have the potential to reduce water usage and enhance recovery factors, particularly from tight oil reservoirs. In contrast, EOR methods that are inherently associated with high carbon intensity, such as thermal EOR, will face stricter constraints to perform, including prohibitive costs for carbon offsetting. Advanced modeling and optimization, including guided machine learning and data analytics, will be crucial to maximizing recovery, quantifying uncertainties, and managing risk while preserving resources and reducing costs. The selected papers in this feature include examples of innovative approaches for developing efficient EOR schemes and advanced modeling and optimization. In one inclusion, optimized water chemistry is engineered for various EOR schemes (e.g., polymer, surfactant, CO2) to improve efficiency while reducing chemical usage. The second inclusion demonstrates an integrated core-to-field work flow to design surfactant-based EOR for a tight formation at the laboratory scale and demonstrate its performance using field-scale simulations. An integrated optimization approach for a Permian CO2-EOR field is demonstrated in the third paper, where an advanced Bayesian framework is used to capture uncertainties. Our industry has consistently demonstrated resilience, adaptivity, and creativity. In the era of industry transition to low-carbon operations, opportunities exist for selective EOR methods to revive and contribute. Recommended additional reading at OnePetro: www.onepetro.org. SPE 208121 Polymer Injection To Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large-Scale Polymer Project by Clement Fabbri, ADNOC, et al. SPE 208127 The World’s First Offshore Gravity-Assisted Simultaneous Water-Alternating-Gas EOR Full-Field Implementation by Ahmad Khanifar, Petronas, et al. SPE 207449 Numerical Optimization of Water-Alternating-Gas Injection in a Sandstone Field Using a Coupled Surface and Subsurface Model by Thaer I. Ismail, Khalifa University of Science and Technology, et al.

Recovery efficiency and characteristics of long core by CO2 flooding in low permeability sandstone reservoirs

CO2 flooding is an economical and efficient enhanced oil recovery technology, however, it is difficult for conventional short core experiments to provide accurate parameters for the later on-site optimization scheme. In this paper, on the basis of long core flooding experiments and applying NMR technology, we quantitatively evaluated the recovery efficiency and remaining oil distribution characteristics by CO2 in low-permeability sandstone reservoirs from a microscopic perspective, and explored the potential of CO2 flooding in low-permeability sandstone reservoirs. Results showed that with the CO2 injection pressure increase, the recovery efficiency of the long core increased and the ultimate recovery was 65.3%. Recovery efficiency of short cores at the inlet, middle and outlet decreases successively, but the change range was not large, and all of them are around the recovery efficiency of long core. In addition, at low injection pressure, almost all CO2 went into the larger pores to replace oil. As increased pressure, the oil started to be produced from the smaller pores, but at 22 MPa, the recovery efficiency in larger pores (76.88%-83.38%) was still higher than that of smaller pores (68.73%-72.74%). Which provided a guide for optimizing the CO2 enhanced oil recovery method in the field.

Mechanism of Hexane Displaced by Supercritical Carbon Dioxide: Insights from Molecular Simulations

Supercritical carbon dioxide (sCO2) has great potential for displacing shale oil as a result of its high solubility and low surface tension and viscosity, but the underlying mechanisms have remained unclear up to now. By conducting equilibrium molecular dynamics (EMD) simulations, we found that the displacing process could be divided into three steps: the CO2 molecules were firstly injected in the central region of shale slit, then tended to adsorb on the SiO2-OH wall surface and mix with hexane, resulting in loose hexane layer on the shale surface, and finally displaced hexane from the wall due to strong interactions between CO2 and wall. In that process, the displacing velocity and efficiency of hexane exhibit parabolic and increased trends with pressure, respectively. To gain deep insights into this phenomenon, we further performed non-equilibrium molecular dynamics (NEMD) simulations and found that both the Onsager coefficients of CO2 and hexane were correlated to increase with pressure, until the diffusion rate of hexane being suppressed by the highly dense distribution of CO2 molecules at 12 MPa. The rapid transportation of CO2 molecules in the binary components (CO2 and hexane) actually promoted the hexane diffusion, which facilitated hexane flowing out of the nanochannel and subsequently enhanced oil recovery efficiency. The displacing process could occur effectively at pressures higher than 7.5 MPa, after which the interaction energies of the CO2-wall were stronger than that of the hexane-wall. Taking displacing velocity and efficiency and hexane diffusion rate into consideration, the optimal injection pressure was found at 10.5 MPa in this work. This study provides detailed insights into CO2 displacing shale oil and is in favor of deepening the understanding of shale oil exploitation and utilization.