Oil Recovery Mechanisms Research Articles

Research on Mechanism of Controlling Water and Stabilizing Production in Heavy Oil Reservoirs with Edge-bottom Water

The development of edge-bottom water heavy oil reservoirs typically involves short water-free production period and a rapid increase in water cut, leading to generally low oil recovery factors. Combining the advantages of foam and viscosity reducers for composite development can effectively address the challenges in edge-bottom water reservoirs; however, the mechanism of action remains unclear. In this study, the concentrations of foaming agent and viscosity reducer were initially determined using a foam evaluator and an Anton Paar rheometer. Subsequently, a 2D large flat plate model was employed to conduct a composite group production experiment after water flooding, and then the change in oil saturation during flooding was analyzed by measuring electrical resistance. Finally, the dynamic curves of flooding were compared to analyze the mechanism of water control and oil stabilization (WCOS). The results indicate that the 2D large flat plate model and the method of inverting saturation field maps can effectively simulate the oil-water flow behavior during the composite flooding process after water flooding. The synergistic mechanism of N2 foam controlling bottom water coning and CO2 enhanced viscosity reducer to reduce viscosity in deep areas was revealed, increasing the overall recovery factor by 10.3% compared to water flooding. The mechanism of the combined oil recovery is clarified, which providing a reference for formulating WCOS plans following water flooding.

Research for the Enhanced Oil Recovery Mechanism of Heavy Oil after Composite Huff and Puff Assisted by Edge-Bottom Water Displacement

Abstract In the late stage of exploiting heavy oil reservoirs with edge-bottom water, we are faced with problems such as high crude oil viscosity, channeling of bottom water, and rapid rise in water cut. To clarify the synergistic effect of N2, CO2, N2 foam, and viscosity reducer in water control and oil increase, and solve the problem of edge-bottom water rushing into production wells, one-dimensional sand-pack huff and puff experiments were carried out. First, the N2 foam huff and puff experiment evaluated the effect of N2 foam on controlling bottom water. Then the viscosity reducer assisted CO2 huff and puff experiment analyzed the synergistic viscosity reduction ability between the two to mobilize the remaining heavy oil. Next, the N2 foam-viscosity reducer-CO2 huff and puff experiment clarified the synergistic effect between the three. Finally, the N2 foam-viscosity reducer-CO2-N2 huff and puff experiment solved the problem of insufficient reservoir energy based on synergistic precipitation and oil increase. Experimental results show that N2 foam-viscosity reducer-CO2-N2 huff and puff is the optimal water control and oil increase solution. This solution can significantly reduce water production and increase oil production. In the one-dimensional sand-pack experiment, this technical solution reduced the water content by 68% and increased the recovery rate by 16.09%. The research results provide a reference for the development of exploitation technology schemes for similar edge-bottom water heavy oil reservoirs after entering high water cut.

Molecular dynamics of quantitative evaluation of confined fluid behavior in nanopores media and the influencing mechanism: Pore size and pore geometry

Understanding the potential mechanisms of reservoir fluid storage, transport, and oil recovery in shale matrices requires an accurate and quantitative evaluation of the fluid behavior and phase state characteristics of the confined fluid in nanopores as well as the elucidation of the mechanisms within complex pore structures. The research to date has preliminary focused on the fluid behavior and its influencing factors within a single nanopore morphology, with limited attention of the role of pore structures in controlling fluid behavior and a lack of quantitative methods for characterizing the phase state of fluids. To address this gap, we utilize molecular dynamics simulations to examine the phase state characteristics of confined fluids across various pore sizes and geometries, revealing the mechanisms by which wall boundary conditions influence fluid behavior. We use the simulation results to validate the accuracy and applicability of the quantitative characterization model for fluid phase state properties. Our findings show that the phase state features of fluids differ significantly between slit-like and cylindrical pores, with lower absorption limits in pore sizes of 2.8 and 7 nm, respectively. Based on pore sizes, we identified three regions of confined fluid phases and determined that the influence of the adsorbed state fraction on fluid phase state cannot be ignored for pores smaller than approximately 85 nm. Additionally, cylindrical pores interact with the internal fluids about 1.8 times stronger than slit-like pores.

3-D Modelling and Simulation of a Reservoir for Surfactant-Polymer Flooding Using Eclipse Software

Surfactant-polymer flooding is a tertiary enhanced oil recovery method used to recover oil that remained in the reservoir after the primary and secondary oil recovery mechanisms. Predicting the pressure in the reservoir is important for oil production as pressure changes with time. A suitable approach to achieve this task is to derive fluid flow equation based on the reservoir characteristics and solve them numerically which provide the solution to the mathematical fluid flow model (diffusivity equation). In this study, 3-D reservoir was modelled using Eclipse software. The fluid flow equations in a porous media were derived based on the simulated model and the reservoir conditions. Numerical solution using implicit formulation to solve the mathematical fluid flow model (diffusivity equation) was investigated by developing Python codes using Jupyter library to ascertain the pressure distribution for the reservoir and imported into Eclipse simulator. Simulation was carried out using surfactant-polymer and reservoir properties to determine the oil recovery. The results of the study showed that pressure increases with time as oil production continued, and water saturation decreased for the grid-cells of the reservoir. Waterflooding had oil recovery of 38.0% and water-cut of 59.0%, while surfactant flooding had oil recoveries of 42.0%, 46.5%, 49.0% and water-cut of 57.0%, 51.0%, 46.3%. In addition, polymer flooding had oil recoveries of 44.3%, 48.4%, 54.0% and water-cut of 50.0%, 45.0% and 33.0% respectively at different concentrations of 0.3%wt. 0.4%wt. and 0.5%wt.

Effect of a SILICA/HPAM Nanohybrid on Heavy Oil Recovery and Treatment: Experimental and Simulation Study.

The addition of nanoparticles has been presented as an alternative approach to counteract the degradation of polymeric solutions for enhanced oil recovery. In this context, a nanohybrid (NH34) of partially hydrolyzed polyacrylamide (MW ∼12 MDa) and nanosilica modified with 2% 3-aminopropyltriethoxysilane (nSiO2-APTES) was synthesized and evaluated. NH34 was characterized by using dynamic light scattering, Fourier-transform infrared spectroscopy, and thermogravimetric analysis. Fluid-fluid tests assessed its viscosifying power, mechanical stability, filterability, and emulsion behavior. Rock-fluid tests were carried out to determine the nanohybrid's adsorption in porous media, the inaccessible pore volume (IPV), and the resistance (RF) and residual resistance factors (RRF). These tests were conducted under the conditions of a Colombian field. NH34 results were compared with four (4) commercial polymers (P34, P88, P51, and PA2). The viscosifying power of NH34 was observed to be similar to that of the four commercial polymers at a lower concentration, but it exhibits more resistance to mechanical and chemical degradation. The evaluation of the emulsion behavior showed that the nanohybrid neither changed the dehydration process nor altered the crude oil viscosity, favoring its extraction at the wellhead. However, the water clarification treatment must be adjusted because the oil and grease contents and turbidity increase with the residual concentration of NH34. Incremental oil recovery factors obtained by numerical simulation (compared to waterflooding) were P51 (5.5%) > P34 (4.9%) > P88 (4.8%) > NH34 (2.6%) > PA2 (0.9%). The polymers P51, P34, and P88 had a better recovery factor than NH34 and PA2 due to their lower values of residual adsorption and IPV. Few studies have been reported on polymer nanohybrids' emulsion and flow behavior. Therefore, further research is needed to enhance our understanding of the fundamental enhanced oil recovery mechanisms associated with polymer nanohybrids.

Enhanced oil recovery and mitigating challenges in sandstone oil reservoirs employing EDTA chelating agent/ seawater flooding

While low salinity water (LSW) holds promise for improving oil recovery, its implementation is comparatively costly due to the substantial volumes of fresh water required to dilute seawater (SW). Additionally, concerns arise regarding potential issues related to LSW, including fines migration in sandstone reservoirs and scale formation in carbonate reservoirs. Chelating agents can be introduced into undiluted SW to bind with metal ions, thereby lowering its salinity. This approach mimics the behavior of LSW injection while overcoming associated challenges. This study involves measuring oil/injected solution interfacial tension (IFT), evaluating sandstone surface wettability alteration, along with conducting different sand pack flooding scenarios using Ethylenediaminetetraacetic acid (EDTA) chelating agent. The aim was to comprehend the EDTA oil recovery mechanisms and determine the optimal concentration of EDTA that minimizes chemical consumption while maximizing oil recovery. The findings indicated that incorporating 5 wt% EDTA into SW significantly reduced IFT from 29.52 mN/m to 4.75 mN/m, making the oil nearly miscible in the solution. Moreover, wettability tests confirmed that a minimum EDTA concentration of 5 wt% is required to shift wettability from oil-wet to strongly water-wet conditions. Sand pack flooding experiments, on the other hand, further demonstrated that this optimized fluid system can potentially recover an additional 16.1 % of oil following SW flooding. Finally, inductively coupled plasma (ICP) analysis revealed a notable increase in metal ion concentration during EDTA flooding, indicating enhanced leaching of metals from the sandstone surface and improved wettability characteristics.

Ion types effect on oil sweep efficiency during engineered waterflooding; an experimental micro-scale study

This study bridges a knowledge gap in oil recovery mechanisms by investigating the influence of water salinity and ion type on oil displacement within porous media, under dynamic flow conditions. Micromodel waterflooding experiments with MgCl2 and Na2SO4 brines at varying ionic strengths (i.e., 0.00832 and 0.832 M), revealed that the high salinity brines considerably boost oil recovery, compared to the low salinity ones. As an instance for MgCl2, the low salinity brine (0.00832 M) resulted in 23% final recovery (one third of which occurred after breakthrough time), while the high salinity one (0.832 M) resulted in 38.5% final recovery (half of which occurred after breakthrough time). High-salinity solutions not only suppressed fingering, observed with low-salinity brines; but also facilitated the formation of stable water-in-oil emulsions, as observed by microscopic images. These emulsions exhibited increased rigidity and elasticity of the interfacial layer, promoting broader fluid distribution within the porous media. Lowering interfacial tension (IFT) – as evidenced by 10–20 % reduction in IFT by increasing brine's salinity - as well as enhancing interfacial viscoelasticity and water-oil emulsion stability were also recognized as the main mechanisms which ultimately led to improved oil displacements at higher salinities.

Improved Amott Method to Determine Oil Recovery Dynamics from Water-Wet Limestone Using GEV Statistics

Counter-current spontaneous imbibition of water is a critical oil recovery mechanism. In the laboratory, the Amott test is a commonly used method to assess the efficacy of brine imbibition into oil-saturated core plugs. The classic Amott-cell experiment estimates ultimate oil recovery, but not the recovery dynamics that hold fundamental information about the imbibition mechanisms. Retention of oil droplets at the outer core surface and initial production delay are the two key artifacts of the classic Amott experiment. This retention, referred to here as the “external-surface oil holdup effect” or simply “oil holdup effect”, often results in stepwise recovery curves that obscure the true dynamics of spontaneous imbibition. To address these holdup drawbacks of the classic Amott method, we modified the Amott cell and experimental procedure. For the first time, using water-wet Indiana limestone cores saturated with brine and mineral oil, we showed that our improvements of the Amott method enabled accurate and reproducible measurements of oil recovery dynamics. Also for the first time, we used the generalized extreme value (GEV) statistics to describe oil production histories from water-wet heterogeneous limestone cores with finite initial water saturations. We demonstrated that our four-parameter GEV model accurately described the recovery dynamics, and that optimal GEV parameter values systematically reflected the key characteristics of the oil–rock system, such as oil viscosity and rock permeability. These findings gave us a more fundamental understanding of spontaneous, counter-current imbibition mechanisms and insights into what constitutes a predictive model of counter-current water imbibition into oil-saturated rocks with finite initial water saturation.

Study on Surfactant-Polymer Flooding after Polymer Flooding in High-Permeability Heterogeneous Offshore Oilfields: A Case Study of Bohai S Oilfield.

Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant-polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant-polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant-polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant-polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant-polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields.

Combining Thermal Effect and Mobility Control Mechanism to Reduce Water Cut in a Sandstone Reservoir in Kazakhstan.

The application of polymer flooding is currently under investigation to control water cut and recover residual oil from a giant sandstone reservoir in Kazakhstan, where the water cut in most producers exceeds 90%, leaving substantial untouched oil in the porous media. The primary objective of this research is to explore the feasibility of a novel approach that combines the mechanisms of mobility control by polymer injection and the thermal effects, such as oil viscosity reduction, by utilizing hot water to prepare the polymer solution. This innovative hybrid method's impact on parameters like oil recovery, resistance factor, and mobility was measured and analyzed. The research involved an oil displacement study conducted by injecting a hot polymer at a temperature of 85 °C, which is higher than the reservoir temperature. Incremental recovery achieved through hot polymer injection was then compared to the recovery by conventional polymer flooding and the conventional surfactant-polymer-enhanced oil recovery techniques. The governing mechanisms behind recovery, including reductions in oil viscosity, alterations in polymer rheology, and effective mobility control, were systematically studied to comprehend the influence of this proposed approach on sweep efficiency. Given the substantial volume of residual oil within the studied reservoir, the primary objective is to improve the sweep efficiency as much as possible. Conventional polymer flooding demonstrated a moderate incremental oil recovery rate of approximately 48%. However, with the implementation of the new hybrid method, the recovery rate increased to more than 52%, reflecting a 4% improvement. Despite the polymer's lower viscosity during hot polymer flooding, which was observed by the lower pressure drop in contrast to the conventional polymer flooding scenario, the recovery factor was higher. This discrepancy indicates that while polymer viscosity decreases, the activation of other oil displacement mechanisms contributes to higher oil production. Applying hybrid enhanced oil recovery mechanisms presents an opportunity to reduce project costs. For instance, achieving comparable results with lower chemical concentrations is of practical significance. The potential impact of this work on enhancing the profitability of chemically enhanced oil recovery within the sandstone reservoir under study is critical.

Assessment of heavy oil recovery mechanisms using in-situ synthesized CeO2 nanoparticles

This project investigated the impact of low-temperature, in-situ synthesis of cerium oxide (CeO2) nanoparticles on various aspects of oil recovery mechanisms, including changes in oil viscosity, alterations in reservoir rock wettability, and the resulting oil recovery factor. The nanoparticles were synthesized using a microemulsion procedure and subjected to various characterization analyses. Subsequently, these synthesized nanoparticles were prepared and injected into a glass micromodel, both in-situ and ex-situ, to evaluate their effectiveness. The study also examined the movement of the injected fluid within the porous media. The results revealed that the synthesized CeO2 nanoparticles exhibited a remarkable capability at low temperatures to reduce crude oil viscosity by 28% and to lighten the oil. Furthermore, the addition of CeO2 nanoparticles to the base fluid (water) led to a shift in the wettability of the porous medium, resulting in a significant reduction in the oil drop angle from 140° to 20°. Even a minimal presence of CeO2 nanoparticles (0.1 wt%) in water increased the oil production factor from 29 to 42%. This enhancement became even more pronounced at a concentration of 0.5 wt%, where the oil production factor reached 56%. Finally, it was found that the in-situ injection, involving the direct synthesis of CeO2 nanoparticles within the reservoir using precursor salts solution and reservoir energy, led to an 11% enhancement in oil production efficiency compared to the ex-situ injection scenario, where the nanofluid is prepared outside the reservoir and then injected into it.

Laboratory study on the transformation of oil-water interface properties under direct current electric field

Interface tension is one of the important mechanisms that affect crude oil recovery and plays an important role in the development of tight oil reservoirs. Electrical-enhanced oil recovery can be used as a technology to reduce interfacial tension and improve crude oil recovery. In the previous research process of Electrical-enhanced oil recovery, the focus was more on the influence of electric field on wettability, and the understanding of the changes in interfacial tension under electric field action is not yet comprehensive. This article designs an orthogonal experiment to study the effect of electric field on oil-water properties. The degree of influence of three factors, namely sodium chloride solution concentration (C), direct current voltage (V), and voltage action time (t), on interfacial tension is studied. Gas chromatography, four component analysis, and Fourier transform infrared spectroscopy are combined to discuss the mechanism of the influence of changes in solution pH, crude oil components, and oil phase functional groups on interfacial tension. The results show that an external electric field can effectively reduce the interfacial tension between oil and water, and the maximum change in interfacial tension after the experiment can be reduced from 23.21 mN/m to 0.37 mN/m; Through range analysis, it can be concluded that the concentration of sodium chloride solution has the greatest impact on interfacial tension, followed by DC voltage and voltage action time. The optimal experimental conditions are 0.5 mol/L sodium chloride solution, 10 V DC voltage, and a voltage action time of 18 h, and the change in interfacial tension is related to the increase in pH value. The change in crude oil composition is also an important reason for the decrease in interfacial tension under external electric fields. Finally, Fourier transform infrared spectroscopy was used to determine that under the action of an electric field, the increase in pH of the sodium chloride solution resulted in the formation of carboxylate salts through chemical reactions between alkaline substances of solution and acidic substances of the oil, which were the key factors in reducing interfacial tension. This study helps to understand and explore the principles and mechanisms of Electrical-enhanced oil recovery in improving oil recovery, with the aim of contributing to the development and promotion of Electrical-enhanced oil recovery technology.

Synergizing shale enhanced oil recovery and carbon sequestration: A novel approach with dual lateral horizontal wells

The dual challenge of enhancing oil recovery while sequestering carbon dioxide (CO2) in oil reservoirs is a pivotal concern in the energy sector. CO2 injection is recognized for its ability to decrease oil density and viscosity, thereby improving oil mobility and recovery rates. Traditionally, efforts have been concentrated either on enhancing oil recovery (EOR) or carbon storage, but not many efforts spent to couple EOR and CO2 sequestration. Hence, novel techniques to optimize engineering designs to synergize EOR with CO2 sequestration is the best approach to maximize the opportunities of storing emission gas and contribute to the global world decarbonization goals.This study introduces an innovative dual lateral horizontal well design, aimed at simultaneously boosting oil recovery from shale reservoirs and enhancing CO2 retention. By integrating a conceptual understanding of oil recovery mechanisms with empirical data from the field, this research contrasts the proposed dual lateral design with the conventional Huff-n-Puff gas injection technique, commonly employed in shale oil formations.Our findings demonstrate that the dual lateral horizontal wells significantly outperform other injection methods in both oil recovery and CO2 storage. Upon optimization, the dual lateral injection design continues to surpass the Huff-n-Puff method in terms of CO2 storage, oil recovery, and net present value (NPV). This investigation not only presents innovative gas injection strategies in shale reservoirs but also provides insights into optimizing gas injection methods to enhance production efficiency and contribute to climate change mitigation through improved carbon capture and storage capacities.Through comprehensive numerical simulations and empirical data analysis, the study explores the optimization of well spacing, revealing that a dual lateral well with optimized spacing between 20 and 30 feet achieves the best outcomes in terms of oil recovery, CO2 retention, and net present value (NPV). The research presents a unique coupling of economic and environmental benefits, supported by economic analysis that includes the potential impact of CO2 tax credits.The novelty of this research is underscored by its integrated approach to CO2-EOR, the development of a dual lateral well design, and the optimization of well spacings for maximized efficiency. By providing a scalable solution that is both economically viable and environmentally sustainable, this research contributes a significant paradigm shift in the field of EOR and CO2 sequestration, with implications for policy and investment strategies in the energy sector. The findings propose a new direction for shale reservoir exploitation, promising to enhance production efficiency while contributing to global efforts in greenhouse gas reduction.

Modified silica nanoparticles stabilized foam for enhanced oil recovery

Foam has been successfully used to improve mobility control in the process of enhanced oil recovery, yet the instability of foam limits its application. Modified nanoparticles with varying wettability were prepared by reacting 3-methacryloxypropyltrimethoxysilane (KH570) with spherical SiO2 nanoparticles in this study. Fourier transform infrared (FTIR) spectra and the measured contact angles were used to characterize the surface properties of the modified SiO2 particles, and the foam stabilization effects of wettability SiO2 were compared. Pore-scale visualization experiments were conducted using a 2D micromodel to identify the prevailing enhanced oil recovery (EOR) mechanisms of modified nano SiO2-Sodium alpha-olefin Sulfonate (AOS) foam flooding. The results indicate that modified SiO2 effectively improves foam stability by adsorbing on the bubble surface and forming a mesh-like structure. The optimum contact angle of the particles is approximately 60°, resulting in a significant increase in drainage half-life by 29.4% compared to foam stabilized only by AOS. Additionally, Foam stabilized by modified SiO2 demonstrates superior dynamic stability and deformation resistance. The modified SiO2 stabilized foam exhibits enhanced interfacial viscoelasticity and plugging and profile control performance, surpassing AOS foam in displacing more residual oil in dead-end pores. The oil recovery of the micro model was determined by ImageJ software. KH570@SiO2 (0.2wt%)-AOS (0.2wt%) foam flooding increased the recovery by 8.7% compared to AOS (0.2wt%) foam flooding.

Decoding the dynamic of CH4 and CO2 displacement for enhanced condensate oil recovery

Gas-condensate reservoirs have attracted wide attention owing to substantial gas and high-quality condensate oil. However, the limited research makes the enhanced oil recovery mechanism through gas injection in condensate reservoirs remains poorly understood. This study explores the intricate molecular interactions of gas displacement in condensate oil recovery. The results underscore that CH4 proves more effective in extracting light components, while CO2 excels in extracting both light and heavy components. Microscopic analysis reveals unique displacement mechanisms, with CH4 displacing light components and forming clusters that concentrate in the center of the pore. In contrast, CO2 induces continuous dispersion and expansion of condensate oil components, thereby extracting more oil from the pore. Additionally, the study emphasizes the influence of pore geometry on condensate oil recovery. These insights provide valuable guidance for optimizing strategies for the gas-driven recovery of condensate oil.

A comprehensive review direct methods to overcome the limitations of gas injection during the EOR process

Among the Enhanced Oil Recovery (EOR) methods, gas-based EOR methods are very popular all over the world. The gas injection has a high ability to increase microscopic sweep efficiency and can increase production efficiency well. However, it should be noted that in addition to all the advantages of these methods, they have disadvantages such as damage due to asphaltene deposition, unfavorable mobility ratio, and reduced efficiency of macroscopic displacement. In this paper, the gas injection process and its challenges were investigated. Then the overcoming methods of these challenges were investigated. To inhibit asphaltene deposition during gas injection, the use of nanoparticles was proposed, which were examined in two categories: liquid-soluble and gas-soluble, and the limitations of each were examined. Various methods were used to overcome the problem of unfavorable mobility ratio and their advantages and disadvantages were discussed. Gas-phase modification has the potential to reduce the challenges and limitations of direct gas injection and significantly increase recovery efficiency. In the first part, the introduction of gas injection and the enhanced oil recovery mechanisms during gas injection were mentioned. In the next part, the challenges of gas injection, which included unfavorable mobility ratio and asphaltene deposition, were investigated. In the third step, gas-phase mobility control methods investigate, emphasizing thickeners, thickening mechanisms, and field applications of mobility control methods. In the last part, to investigate the effect of nanoparticles on asphaltene deposition and reducing the minimum miscible pressure in two main subsets: 1- use of nanoparticles indirectly to prevent asphaltene deposition and reduce surface tension and 2- use of nanoparticles as a direct asphaltene inhibitor and Reduce MMP of the gas phase in crude oil was investigated.

Spontaneous imbibition of modified salinity brine into different lithologies: an improvement of comprehensive scaling used for fractured reservoir simulation

Spontaneous water imbibition into matrix blocks can be a significant oil recovery mechanism in fractured reservoirs. Many enhanced oil recovery methods, such as injection of modified salinity brine, are proposed for improving spontaneous imbibition efficacy. Many scaling equations are developed in the literature to predict spontaneous imbibition oil recovery. However, almost none of them included the impact of the diversity in ionic composition of injected and connate brines and the blending/interaction of a low salinity imbibing brine with a higher salinity connate brine. In this research, these two issues are included to propose new scaling equations for the scaling of spontaneous imbibition oil recovery by modified salinity imbibing brines. This study uses experimental data of the spontaneous imbibition of modified salinity brines into oil-saturated rock samples with different lithologies containing an irreducible high salinity connate brine. The collected tests from the literature were performed at high temperatures and on aged altered wettability cores. The results of 110 available spontaneous imbibition laboratory experiments (85, 12 and 13 tests on chalks, dolomites and sandstones, respectively) are gathered. This research initially shows the poor ability of three selected convenient scaling equations from the literature to scale imbibition recovery by modified salinity brine. Then, our newly proposed technique to find the scaling equation for spontaneous imbibition recovery by modified salinity brine, during the abovementioned conditions in limestones (Bassir et al. in J Pet Explor Prod Technol 13(1): 79–99, 2023. https://doi.org/10.1007/s13202-022-01537-7) is used in chalks, dolomites and sandstones to develop the three new scaling equations. Finally, a new general equation to scale imbibition recovery by modified salinity brine for all four lithologies is presented. Moreover, for each of the four datasets (chalk, dolomite, sandstone and all the four lithologies), the scaled data by the new equations is matched by two mathematical expressions based on the Aronofsky et al. model and the Fries and Dreyer model. These mathematical expressions can be used to develop transfer functions in reservoir simulators for a more accurate prediction of oil recovery by spontaneous imbibition of modified salinity brine in fractured reservoirs.

Effect of jet cavitation on oil recovery from oily sludge

Jet cavitation method was proposed to treat oily sludge to improve oil recovery. The key components affecting the oil desorption efficiency were analyzed by TLC-FID (Thin-layer chromatography and flame ionization detection) method and FT-IR(Fourier-transform infrared spectroscopy), and the mechanism of oil recovery from oily sludge enhanced by jet cavitation was revealed. The results show that when the inlet pressure is 12 MPa, the temperature is 35 °C, the solid concentration is 25 %, and the hydraulic retention time for oily sludge is 4 s, the maximum oil recovery rate is 82.3 %, which is much higher than that after ultrasonic cavitation. After jet cavitation, the sedimentation performance of the oily sludge was improved, and the average particle size was reduced. Asphaltenes and resins are the main components affecting oil desorption. Heteroatoms such as N, S, and O form stable hydrogen bonds with the surface of solid particles, which impede the oil desorption process. The mechanical effect such as micro-jet shock waves and shear forces generated by jet cavitation could disrupt the hydrogen bonds, promoting the reformation of hydrogen bonds between water and solid particles, leading to the separation of oil from the surface of solid particles.

Experimental Study on Improving Oil Recovery Mechanism of Injection–Production Coupling in Complex Fault-Block Reservoirs

In order to improve the effect of injection–production coupling development to improve crude oil recovery in complex fault-block reservoirs, we carried out a physical simulation experiment based on a sandpack model of transforming water-driven development into injection–production coupling development and quantitatively evaluated the influence of rounds of injection pressure coupling on the crude oil mobilization in reservoirs with different permeability levels and on oil recovery. Meanwhile, the characteristics of residual oil were studied via a numerical simulation method. The mechanism of increased oil production via injection–production coupling development was revealed by analyzing the water and oil contents, formation pressure, and streamline fields through the establishment of mechanism models. The results of the physical experiment show that injection–production coupling can improve the recovery effect of medium- and low-permeability reservoirs by 55.66%. With an increase in the injection pressure, the oil recovery percentage of the low-permeability sandpack model at 20 MPa is 100%, and this study finds that injection–production coupling is the main way to develop the recoverable oil in a low-permeability reservoir. The numerical simulation results show that among the four remaining oil distribution types (interwell-enriched, low-permeability zone-enriched, well network imperfection, and mismatch between injection and production), the interwell-enriched type of the remaining oil reserves accounts for the highest proportion (48.52%). The simulation results of the mechanism model show that water-driven development easily leads to streamline solidification, resulting in ineffective circulation of the injected water. Compared with conventional water-driven development, the pressure propagation range is significantly increased in injection–production coupling development. The reservoir streamline distribution is more continuous and uniform, and the flooding wave is wider in volume and range. This research provides a theoretical basis for the injection–production coupling technology policy in complex fault-block reservoirs.

A Laboratory Experimental Study on Enhancing the Oil Recovery Mechanisms of Polymeric Surfactants.

In order to evaluate the physical and chemical properties of polymer surfactants and analyze their oil displacement mechanisms, three types of poly-surfactant used in the Daqing oil field were chosen to be researched, and the oil displacement effects were studied using poly-surfactants of different viscosity, dehydrating rate, and core permeability. The main purpose is to determine the reasonable range of different characteristic indexes of polymeric surfactant flooding. The oil displacement effect of 15 cores was analyzed, and the effects of viscosity, the dehydrating rate of emulsion, and permeability on EOR (Enhanced Oil Recovery) were analyzed. The oil displacement mechanisms of polymeric surfactants were researched using a photolithographic glass core. This paper explores the mechanism underlying production enhancement as an EOR target, while simultaneously conducting laboratory tests to assess the physical and chemical properties of polymeric surfactants. The poly-surfactant agents exhibit a notable increase in viscosity, with the optimal displacement effect observed at a core effective permeability exceeding 400 mD, resulting in a potential EOR of 15% or higher. Moreover, at a viscosity ranging between 40 and 70 mPa·s, the total EOR can reach 73%, with the peak efficiency occurring at a viscosity of 60 mPa·s. The water loss rate of the emulsion, ranging between 30% and 70%, achieves optimal performance at 50%. The poly-surfactants' higher viscosity extends the oil sweep area, enhancing recovery efficiency, and noticeably reducing residual oil compared to water flooding. During poly-surfactant flooding, a substantial amount of residual oil is extracted and transformed into droplets. The rapid emulsification of the polymeric surfactant solution with crude oil forms a stable emulsion, contributing to its significant oil recovery effect. This research provides valuable technical support for EOR in thin and low-quality reservoirs of onshore multi-layered sandstone reservoirs.