Affect Oil Recovery Research Articles

Computational Modeling and Experimental Investigation of CO2-Hydrocarbon System Within Cross-Scale Porous Media

CO2 flooding plays a crucial role in enhancing oil recovery and achieving carbon reduction targets, particularly in unconventional reservoirs with complex pore structures. The phase behavior of CO2 and hydrocarbons at different scales significantly affects oil recovery efficiency, yet its underlying mechanisms remain insufficiently understood. This study improves existing thermodynamic models by introducing Helmholtz free energy as a convergence criterion and incorporating adsorption effects in micro- and nano-scale pores. This study refines existing thermodynamic models by incorporating Helmholtz free energy as a convergence criterion, offering a more accurate representation of confined phase behavior. Unlike conventional Gibbs free energy-based models, this approach effectively accounts for confinement-induced deviations in phase equilibrium, ensuring improved predictive accuracy for nanoscale reservoirs. Additionally, adsorption effects in micro- and nano-scale pores are explicitly integrated to enhance model reliability. A multi-scale thermodynamic model for CO2-hydrocarbon systems is developed and validated through physical simulations. Key findings indicate that as the scale decreases from bulk to 10 nm, the bubble point pressure shows a deviation of 5% to 23%, while the density of confined fluids increases by approximately 2%. The results also reveal that smaller pores restrict gas expansion, leading to an enhanced CO2 solubility effect and stronger phase mixing behavior. Through phase diagram analysis, density expansion, multi-stage contact, and differential separation simulations, we further clarify how confinement influences CO2 injection efficiency. These findings provide new insights into phase behavior changes in confined porous media, improving the accuracy of CO2 flooding predictions. The proposed model offers a more precise framework for evaluating phase transitions in unconventional reservoirs, aiding in the optimization of CO2-based enhanced oil recovery strategies.

Experimental Investigation of Factors Affecting Oil Recovery and Displacement Efficiency of CO2 Injection in Carbonate Reservoirs

Summary Miscible gas injection is the most widely applied enhanced oil recovery (EOR) method in light oil carbonate reservoirs as a tertiary and secondary method. Miscible gas has high displacement efficiency and usually results in a low residual oil saturation (Sorm) in the parts of the reservoirs that are in contact with the gas. Accurate determination of Sorm and understanding the parameters that affect displacement efficiency are crucial for successful miscible gas EOR projects. In this paper, we present a comprehensive experimental program designed to investigate the effect of a number of parameters on oil recovery, displacement efficiency, and Sorm of miscible and near-miscible carbon dioxide (CO2) injection. The parameters investigated in this study are the experimental pressure, pore volume (PV) injected, injection rate, rock type, and initial water saturation (Swi). The coreflood experiments were performed using live crude oil at pressures starting below the minimum miscibility pressure (MMP) to pressure well above the MMP, using reservoir core samples of up to 1 ft long and 2 in. diameter. All CO2 injection experiments were performed using vertically oriented cores, with gas injection from the top to ensure stable displacement. The experimental results show that (1) Oil recovery decreases as pressure decreases with Sorm increasing by more than 20 saturation units as the pressure decreases from 4,250 psi to 2,700 psi; (2) CO2 breakthrough was much earlier at lower pressure, which leads to more CO2 recycling and potentially lower CO2 sequestration volume; (3) the recovery factor (RF) is strongly affected by the PV injected, and this effect is much more significant for the experiments performed at lower pressure; (4) the injection rate has an insignificant impact on oil recovery and Sorm for miscible or near-miscible CO2, due to the low interfacial tension (IFT) between oil and CO2; (5) rock heterogeneity has a strong effect on oil recovery and CO2 breakthrough and hence on CO2 recycling and economy of the projects; and (6) the presence of mobile water at the beginning of CO2 injection resulted in lower displacement efficiency and increased Sorm. However, this water blocking effect should be determined experimentally for a given reservoir rock/fluid system. The results of this study cannot be generalized for other reservoirs. The results of this study have important implications for the design and performance predictions of CO2 injection in the reservoirs under study. Starting CO2 injection at reservoir pressure, which, in some cases, is more than 1,500 psi above MMP, is recommended due to its superior displacement efficiency and less CO2 recycling due to later breakthrough. However, a higher pressure may negatively impact the required CO2 volume, the compression cost, and project economics.

Computational study of the thermophysical properties of graphene oxide/vacuum residue nanofluids for enhanced oil recovery

AbstractPrior research suggests that the use of nanotechnology may greatly improve the efficiency of enhanced oil recovery methods, especially hot fluid injection. The thermophysical characteristics of the nanofluid may have an enormous effect on how well the injection process works. However, it takes both time and resources to conduct laboratory analyses of the effects of thermophysical characteristics on the effectiveness of nanofluid-based improved oil recovery methods. Computational models can effectively forecast the thermophysical characteristics of nanofluids and how they affect oil recovery efficiency, which helps overcome this difficulty. The current study investigates the flow of vacuum residue (VR) fluid, which generates entropy when suspended graphene oxide (GO) nanoparticles. When mixed convection and variable thermal conductivity are present, a static/moving wedge allows the nanofluid to propagate. The continuity, energy, entropy, and momentum equations form the foundation of the governing model. We use certain similarity variables to simplify the suggested mathematical formulations into forms for nonlinear differential equations (DEs). We show the results of the reduced equations using the Chebyshev collocation method. We present the graphical and numerical results for all the emerging parameters. For enhanced oil recovery applications, the current results are beneficial.

Investigation of oil-based CO2 foam EOR and carbon mitigation in a 2D visualization physical model: Effects of different injection strategies

CO2 flooding in low-permeability and tight oil reservoirs often encounters gas channeling, which affects oil recovery. To address this, oil-based CO2 foam development is explored using a two-dimensional visual physical model. The study includes three experimental setups: CO2 flooding followed by oil-based CO2 foam flooding, CO2 Huff-n-Puff (HnP) followed by oil-based CO2 foam HnP, and oil-based CO2 foam HnP followed by oil-based CO2 foam flooding. Findings reveal that using oil-based CO2 foam after CO2 development increases recovery factors by 15.62% and 35.86% for HnP and flooding, respectively, and significantly boosts CO2 storage. The CO2 storage is 1.96 times and 6.03 times higher than the initial one. After oil-based CO2 foam is used, the red area near the outlet of the visualization model becomes shallower, indicating a further decrease in residual oil saturation. The oil-based CO2 foam method reduces residual oil saturation and extends production duration while decreasing gas production rates. This approach effectively plugs gas channels, enhancing CO2 sweep efficiency, crude oil mobility, and recovery. The results provide innovative strategies for oilfield development, supporting carbon sequestration and offering substantial economic and environmental benefits.

Fingering inhibition triggered by CO2 dissolution and viscosity reduction in water-alternating-CO2 injection

As a CO2 capture, utilization, and storage (CCUS) technology, water-alternating-CO2 (WAG) injection has demonstrated excellent results in enhancing oil recovery. Current research on WAG injection primarily focused on factors such as increasing injection pressure and optimizing the water–gas slug ratio (W:G) to enhance the driving force, reduce instability due to the significant viscosity difference between oil and CO2, thereby inhibiting fingering phenomenon and improving oil recovery. However, in immiscible flooding, CO2 dissolution reduces the viscosity of the oil, changing the instability of the interfaces and affecting oil recovery. We employed computational fluid dynamics to study the effect of CO2 dissolution and viscosity reduction on fingering patterns and its effect on enhanced oil recovery (EOR) under capillary numbers Ca = 0.12 × 10−2–1.14 × 10−2 and W:G = 1:3–3:3. The results indicated that: (1) the dissolution of CO2 reduced oil viscosity, inhibiting the fingering phenomenon, promoting stable displacement and enhancing oil recovery. (2) The viscosity reduction effect of CO2 dissolution was more effective in viscous fingering. (3) Analysis of the EOR capacity after injecting a unit volume of displacement fluid confirmed that the optimal W:G remains 1:3. These findings highlight the importance of considering CO2 dissolution and its viscosity reduction effect to optimize WAG injection strategies for enhanced oil recovery.

Investigation on the impact of CO2-Induced precipitation on microscopic pore structure of low-permeable reservoirs

CO2 injection into reservoirs might induce organic or inorganic precipitation in microscopic pores, and some of the pores are blocked by the precipitates, resulting in a decrease in the connectivity of pores and affecting oil recovery. In this paper, a set of experiments on CO2 displacement and CO2-water-oil-rock interaction are conducted to study the microscopic mechanisms of reservoir damage. In-situ Nuclear Magnetic Resonance (NMR) technology is applied to conduct the microscopic analysis of CO2-EOR and reservoir damage at real reservoir conditions. The results reveal that the particle size and the amount of inorganic precipitates formed in the formation water will increase with the rise of CO2 injection pressure, and the inorganic precipitates primarily consist of siderite and kaolinite. The change of NMR T2 spectra of the core samples reveals that the inorganic precipitates primarily block the small pores less than 0.89 μm. However, as a result of stronger mineral dissolution and solute transport, the pore volume of the large pores (greater than 0.89 μm) increases after the CO2-water-rock reaction. Ultimately, this interaction results in a 5.4% increment in pore volume. In addition, the displacement efficiency of water-saturated cores is improved after the first CO2 displacement, which indicates that CO2-water-rock interaction can effectively improve the seepage properties of reservoirs. Nevertheless, the reservoir damage caused by asphaltene precipitation during CO2 flooding is more significant. The asphaltene precipitation percentage in formation oil increases with the rise of CO2 injection pressure, reservoir temperature, and asphaltene content in virgin oil. CO2-induced asphaltene precipitation causes more severe blockage on small pores in comparison with large pores. After 2 h of CO2 injection to the oil-saturated core, permeability and oil recovery caused by CO2-induced precipitation decreased by 17.6% and 11.4%, respectively.

Effect of Pore Structure on Tertiary Low-Salinity Waterflooding in Carbonates: An In-Situ Experimental Investigation

Summary Low-salinity waterflooding (LSW) is an environmentally friendly and economically feasible technology that enhances oil recovery by controlling ionic composition or brine salinity. The recovery efficiency of this technique is strongly affected by the rock pore structure that governs the flow behavior of the injected brine. However, existing experimental studies elaborating on the relationship between pore structure and LSW performance in carbonates remain scarce. To address this gap, three carbonate plugs with different pore structures were displaced sequentially with synthetic high- and low-salinity brine under the capillary-dominated flow regime. High-resolution micro-computed tomography (CT) was used to obtain 3D images of different displacement stages, visualizing the fluid distribution. After image processing and contact angle calculation, it was found that the primary mechanism for enhanced recovery was wettability alteration, transitioning from oil-wet to weakly oil-wet. Significant differences were observed among the three samples. Sample 1 showed the highest additional recovery (22.2%), followed by Sample 2 (11.2%), and the lowest was Sample 3 (4.5%). Despite Sample 1 and Sample 3 having similar and narrow pore size distributions, they exhibited different fluid behaviors during LSW: In Sample 1, oil was mainly displaced from medium-sized pores, whereas in Sample 3, small pores were the main target for brine. The large coordination number likely enhanced the relative permeability of the high-salinity brine. The low-salinity brine followed the pathway formed by the high-salinity brine, affecting the LSW performance. This work provides novel insights into how pore structure affects oil recovery by comparing the response of multiple carbonate samples to LSW.

An experimental study on the wettability of nanofluids

The wettability of nanofluid is a key factor affecting oil recovery and fluid heat transfer. However, the traditional wettability measurement method consisting in determining the contact angle enables to assess the wettability at a solid–liquid contact point only and not within the continuous detection range. Therefore, in this work, a lateral friction detection system is used to continuously measure the wettability of hydroxylated multi-walled carbon nanotubes/deionized water (MWCNT-OH/DIW) nanofluids on polydimethylsiloxane surfaces. Specifically, MWCNT-OH/DIW nanofluids with various mass fractions are configured, and different surfactants are introduced to regulate the dispersion in deionized water. The results reveal that the surface tension and contact angle decrease simultaneously with the increase in MWCNT-OH/DIW mass fraction. Meanwhile, this change also causes an increase in the lateral friction at the nanofluid/PDMS interface. Furthermore, both sodium dodecyl sulfate and cetyltrimethylammonium bromide (CTAB) as surfactants can effectively reduce its surface tension. Notably, when CTAB is added, the maximum static friction (132.62 μN) exceeds that of SDS (113.13 μN). Therefore, the proposed method opens up new prospects in wettability detection of nanofluids.

Experimental Study on Factors Affecting Oil Recovery in Sandstone-Buried Hill Superimposed Reservoirs.

Sandstone-buried hill superimposed reservoirs, characterized by the coexistence of the sandstone matrix and the fracture pore matrix, present unique challenges in integrated development due to their connectivity and physical properties. Currently, research on the factors affecting the recovery of sandstone-buried hill superimposed reservoirs with both porous and fractured media is limited. In this study, a more realistic method for preparing fractured cores and calculating fracture permeability was proposed, and the effect of confining pressure on fracture permeability was investigated. Additionally, a three-tube experimental apparatus was designed to study the effects of connectivity, different permeability contrasts between sandstone and buried hills, and various development strategies on recovery. The results indicate that fracture permeability is significantly affected by the confining pressure. When sandstone and buried hills are not connected, the total recovery is the highest. As connectivity increases, the recovery from sandstone gradually decreases, while the recovery from the buried hill gradually increases, leading to a decrease in the overall recovery. The permeability contrast between sandstone and buried hill has a minimal impact on the overall recovery; however, a higher permeability contrast leads to increased sandstone recovery and decreased buried hill recovery. The highest overall recovery was achieved with injection solely into the sandstone, followed by general injection, with the lowest recovery from injection solely into the buried hill. This study provides new insights into the integrated development of sandstone-buried hill reservoirs.

The flooding mechanism and oil recovery of nanoemulsion on the fractured/non-fractured tight sandstone based on online LF-NMR experiments

Hydraulic fracturing and water/nanoemulsion flooding technology are effective stimulation measures for tight oil production. The complex pore structure of ultra-low permeability sandstone greatly affects oil recovery. At present, scholars have done a lot of research on the characteristics of oil-water flow in micro-nano pores of ultra-low permeability sandstone reservoirs. However, few scholars have comprehensively studied the whole process of ultra-low permeability sandstone reservoirs from hydraulic fracturing to enhanced oil recovery. In this paper, the whole process from fracturing to production of ultra-low permeability sandstone reservoirs is comprehensively studied at the laboratory scale by combining triaxial fracturing, CT scanning, online LF-NMR and other technologies, aiming to promote the understanding of tight oil development. The results show that the high confining pressure (45 MPa) inhibits the propagation of fractures in the rock samples more than the low confining pressure (15 MPa) during the triaxial fracturing process. The oil recovery of the rock sample with high fracture volume (1213.42 mm3) is 16.32 % higher than that of the rock sample with low fracture volume (674.22 mm3). Whether it is fractured rock or non-fractured rock, nanoemulsion can further improve the oil recovery of micropores on the basis of water flooding, with a maximum increase of 28.21 %. The oil recovery of the nanoemulsion with a concentration of 0.3 wt% was 25.34 % higher than that of the nanoemulsion with a concentration of 0.05 wt%. Confining pressure conditions have an important impact on oil recovery. The oil recovery of non-fractured rock samples with initial confining pressure of 5 MPa is 8.15 % lower than that of non-fractured rock samples with initial confining pressure of 30 MPa. At the same time, we propose a new T1-T2 map region division scheme based on sandstone to better characterize oil displacement behavior at the pore scale. The research results can guide the exploitation of ultra-low permeability sandstone reservoirs.

Seepage Simulation of Conglomerate Reservoir Based on Digital Core: A Case Study of the Baikouquan Formation in Mahu Sag, Junggar Basin

Pore structure and flow characteristics are key factors affecting oil recovery rates in heterogeneous tight conglomerate reservoirs. Using micron computed tomography (CT) and modular automated processing system (MAPS) techniques, the pore structure of downhole core samples taken from Mahu’s tight conglomerate reservoirs was analyzed in detail, and a two-scale digital core pore network model with both a wide field of view and high resolution was constructed based on these pore structure data; the digital pore model was corrected according to the mercury intrusion pore size distribution date. Finally, we simulated flow characteristics within the digital model and compared the calculated permeability with the indoor permeability test date to verify the dependability of the pore network. The results indicated that the pore–throat of the conglomerate reservoir in Mahu was widely distributed and exhibited significant bimodal characteristics, with main throat channels ranging from 0.5 to 4 μm. The pore structure showed pronounced microscopic heterogeneity and intricate modalities, mainly consisting of dissolved pores, intergranular pores, and microfractures. These pores were primarily strip-like, isolated, and played a more crucial role in enhancing pore connectivity rather than contributing to the overall porosity. The matrix pores depicted by the MAPS were relatively smaller in size and more abundant in number, with no individual pore type forming a functional seepage channel. The permeability parameters obtained from the two-scale coarse-fine coupled pore network aligned with the laboratory experimental results, displaying an average coordination number of two. Flow simulation results indicated that the core’s microscopic pore structure affected the shape of the displacement leading edge, resulting in a tongue-in phenomenon during oil–water flow. The dominant flow channel was mainly dominated by water, while tongue-in and by-pass flow were the primary microscopic seepage mechanisms hindering oil recovery. These findings lay a foundation for characterizing and analyzing pore structure as well as investigating flow mechanisms in conglomerate reservoirs.

Experimental study on countercurrent imbibition in tight oil reservoirs using nuclear magnetic resonance and AFM: Influence of liquid–liquid/solid interface characteristics

Countercurrent imbibition of the fracturing fluid is of much significance for enhancing oil production in tight oil reservoirs during the shut-in period after hydraulic fracturing. The addition of enhanced imbibition agents such as surfactants and nanoparticles into the polymer-based fracturing fluid is conducive to oil production. How different types of imbibition agents affect oil recovery and the applicable conditions for different imbibition agents, however, still need to be clarified. In this article, we used low-field nuclear magnetic resonance (NMR) to measure the one-dimensional (1D) oil signal profiles along the imbibition direction during the countercurrent imbibition process and determine the imbibition distance and water saturation of different imbibition agents including polymer, surfactant, nano-silica (NS) and NS-surfactant complexes. Moreover, by measuring oil–water interfacial tension (IFT), and the adhesion forces between alkanes and the hydrophobic surfaces before/after the imbibition agent treatments by atomic force microscope (AFM), the IFT reduction and wettability alteration abilities of these agents were evaluated. After the NS-surfactant complexes treatment, the adhesion force which represents the force required to pull off oil from the rock surface became the lowest (15.81 pN), merely a quarter of that of NS (73.48 pN) and surfactant (70.01 pN), indicating a superior capability of NS-surfactant to improve wettability. The imbibition efficiency of the four systems in terms of imbibition distance and oil recovery was: NS-surfactant complexes: 38.43 mm 13.2 % > nonionic surfactant: 32.15 mm 9.0 % > NS: 25.88 mm 7.6 % > polymer: 17.64 mm 4.9 %. NS-surfactant nanofluid displayed the longest imbibition distance and highest water saturation, thus possessing the highest imbibition oil recovery. Nonionic surfactant with an IFT of 4.19 mN/m could greatly reduce the IFT compared with NS (35.98 mN/m), but the recovery enhancement induced by IFT reduction was not significant. In contrast, the increase in oil recovery by wettability alteration was distinctly higher than that by IFT reduction, as indicated by the recovery difference between NS-surfactant complexes and surfactant. Accordingly, wettability alteration is the primary mechanism to enhance imbibition oil recovery when ultralow IFT cannot be achieved. This research provides guidance on which type of imbibition agent should be selected to improve imbibition efficiency.

Compositional Streamline-Based Modeling of Polymer Flooding Including Rheology, Retention, and Salinity Variation.

The chemical enhanced oil recovery (CEOR) technology that is most used worldwide is polymer flooding due to its proven commercial success at field scale, maturity, and versatility to combine with other technologies. So, there has been an increasing interest in expanding its applicability to more unfavorable mobility ratio conditions and adverse environments (such as high-temperature, high-salinity carbonate reservoirs, pH-sensitive polymers, and formations with active clays). Therefore, a requirement for successful field application is to find the design parameters of the process that balance material requirements and oil recovery benefits in a cost-effective manner, which is usually done through reservoir modeling. Polymer flooding predictive tools normally require detailed information and are based on time-consuming field reservoir simulations. Thus, for effective project management, a quick and sound tool is needed to screen for polymer flooding applications without giving up key physical-chemical phenomena that govern the oil recovery. In this research, we developed a two-dimensional polymer flooding model based on the streamlines approach. This is an alternative to having a multidimensional practical tool thoroughly representing the physical and chemical behavior of polymer flooding by considering key phenomena such as rheology behavior (shear thinning and shear thickening), salinity variations, permeability reduction, and polymer adsorption. Previously published streamline multidimensional models for polymer flooding lack the integrated modeling of the above-mentioned key phenomena. Additionally, the models to represent rheology and retention phenomena in the proposed tool consider a more complete description than the present streamline-based simulators. For the construction of streamlines, we considered a black oil formulation to estimate the pressure and saturation 2D distribution by applying the implicit in pressure and explicit in saturation method, coupled with an explicit formulation for the 2D composition computation. For saturation-composition along the streamlines, the 1D practical tool incorporated represents the polymer flooding key phenomena. The numerical algorithm used by the streamline-based tool is supported by laboratory experiments for waterflooding in homogenous porous media, analytical results for waterflooding in heterogeneous media, polymer flooding field scale simulation cases, and a CMG-STARS model built as a reference for waterflooding in both media (homogenous and heterogeneous) and for polymer flooding. The practical tool developed contributes to simplifying the upscaling from laboratory observations to field applications with better fitted numerical simulation models and to determining favorable scenarios; thus, it could assist in understanding how key parameters affect oil recovery without performing time-consuming CEOR simulations.

Heavy Alkyl-Benzene Sulfonate-Controlled Growth of Aragonite-Based Polymorphic CaCO3 Crystals in Emulsion

The non-natural mineralization of CaCO3 with special structures or morphologies is generated during the migration of crude oil and is the main form of scale in alkaline/surfactant/polymer (ASP) flooding in oilfields, adversely affecting oil recovery and causing environmental pollution. To date, the mineralization of aragonite superstructures and the role of heavy alkyl-benzene sulfonate (HABS) in mineralization are still unclear. In this work, aragonite-based superstructures of CaCO3 crystals were obtained in an O/W emulsion with HABS to help deepen the understanding of the diversified growth of CaCO3 scaling in oilfields. As a result, rosette-like, bouquet-like, and dumbbell-shaped CaCO3 crystals with vaterite–aragonite, aragonite, and calcite–aragonite phases were formed with 200 mg/L HABS concentration at 45 °C for 60 min and spherical vaterite phase stabilized at a high HABS concentration (800 mg/L and 1000 mg/L). Rhombohedral calcite content experienced a fluctuation of about 40% as the HABS concentration varied. Needle-like and bundle-like aragonite precipitates were generated with increasing temperatures from 65 °C to 85 °C. Thus, HABS affects the nucleation and growth of the precipitated CaCO3 solid, leading to modifications in the structure and morphology of the crystals. The synergistic effect between HABS and temperature can regulate ion pairs with the calcium ions and block sites that are essential to the incorporation of new solutes into the crystal lattice, which leads to the heterogeneous nucleation of vaterite and aragonite on calcite, forming aragonite-based superstructures in kerosene emulsion. This work may enrich the understanding of CaCO3 mineralization in oilfields, and also provide a novel strategy for manufacturing organic–inorganic composites.

Insights into Enhanced Oil Recovery by Coupling Branched-Preformed Particle Gel and Viscosity Reducer Flooding in Ordinary Heavy Oil Reservoir

Viscosity reducer flooding has been successfully applied in tertiary oil recovery of ordinary heavy oil reservoirs. However, lowering interfacial tension or reducing oil viscosity, which is more critical for viscosity reducer to improve oil recovery of ordinary heavy oil, has not yet formed a unified understanding, which restricts the further large-scale application of viscosity reducer flooding for ordinary heavy oil reservoir. Moreover, when the dominant water flow channel is formed in the reservoir, the sweep efficiency decreases sharply and can affect oil recovery efficiency of viscosity reducer. Therefore, in this study, the concept of branched-preformed particle gel (B-PPG) coupling viscosity reducer flooding is proposed. The oil-water interfacial tension performance, emulsification ability, and viscosity reduction performance of three different viscosity reducers were evaluated. The enhanced oil recovery ability of viscosity reducers, B-PPG, and viscosity reducer/B-PPG composite systems was investigated by performing sand pack flooding experiments. The results show that the oil-water interfacial tensions of the three viscosity reducers S1, S2, and S3 are 0.432 mN·m-1, 0.0112 mN·m-1, and 0.0031 mN·m-1, respectively. S1 with the highest interfacial tension has the best emulsification and viscosity reduction performance, S2 is the second, and S3 is the worst. The lower the interfacial tension, the worse the emulsification stability. The sand pack flooding results show that the incremental oil recovery of viscosity reducer S2 flooding is the largest, 7.5%, followed by S1, 7.3%, and S3, 5.6%. The viscosity reducer S2 with moderate interfacial tension and emulsifying capacity has the best ability to improve the recovery of ordinary heavy oil. The incremental oil recovery of B-PPG is 12.7%, which is significantly higher than that of viscosity reducer flooding. Compared with viscosity reducing flooding, the viscosity reducer/B-PPG composite systems have better enhanced oil recovery capacity. The findings of this study can help for better understanding of enhancing oil recovery for ordinary heavy oil reservoir.

Influence of Henna Extracts on Static and Dynamic Adsorption of Sodium Dodecyl Sulfate and Residual Oil Recovery from Quartz Sand.

The application of surfactant flooding for enhanced oil recovery (EOR) promotes hydrocarbon recovery through reduction of oil-water interfacial tension and alteration of oil-wet rock wettability into the water-wet state. Unfortunately, surfactant depletion in porous media, due to surfactant molecule adsorption and retention, adversely affects oil recovery, thus increasing the cost of the surfactant flooding process. Chemical-based materials are normally used as inhibitors or sacrificial agents to minimize surfactant adsorption, but they are quite expensive and not environmentally friendly. Plant-based materials (henna extracts) are far more sustainable because they are obtained from natural sources. However, there is limited research on the application of henna extracts as inhibitors to reduce dynamic adsorption of the surfactant in porous media and improve oil recovery from such media. Thus, henna extracts were introduced as an eco-friendly and low-cost sacrificial agent for minimizing the static and dynamic adsorption of sodium dodecyl sulfate (SDS) onto quartz sand in this study. Results showed that the extent of surfactant adsorption was inversely proportional to the henna extract concentration, and the adsorption of the henna extract onto the quartz surface was a multilayer adsorption that followed the Freundlich isotherm model. Precisely, the henna extract adsorption on quartz sand is in the range of 3.12-4.48 mg/g (for static adsorption) and 5.49-6.73 mg/g (for dynamic adsorption), whereas the SDS adsorption on quartz sand was obtained as 2.11 and 4.79 mg/g at static and dynamic conditions, respectively. In the presence of 8000 mg/L henna extract, SDS static and dynamic adsorption was significantly reduced by 64 and 82%, respectively. At the same conditions, the residual oil recovery increased by 9.2% over normal surfactant flooding. The study suggests that the use of henna extracts as a sacrificial agent during SDS flooding could result in the reduction of static and dynamic adsorption of surfactant molecules on quartz sand, thus promoting hydrocarbon recovery from sandstone formations.

Design of injected water salinity for enhanced oil recovery applications in sandstone reservoirs using coupled flow-geochemical simulation

Many previous studies have highlighted the effect of injected fluid salinity on recovery performance and effluent analysis in sandstone reservoirs. However, the complex interactions between the oil, original formation water, injected water, and rocks make capturing all the relevant mechanisms difficult. This paper presents a simulation study where complex mechanisms and interactions are represented, including multiple ion exchange, mineral dissolution, wettability alteration, pH variation, and electrical double layers. The models are used to examine how the salinity of injected water may affect oil recovery and compositions of the effluent fluids. The results show that the wettability changes caused by ion exchange and mineral dissolution/precipitation reactions may strongly affect the recovery performance of low-salinity water injection. In contrast, mineral dissolution/precipitation effects are less significant for high-salinity water injection. In addition, the complex interactions between these processes also affect the pH in the effluent (producing) streams.

On the assessment of the diversity of coefficients of oil recovery from developed objects


 
 
 Based on the geological and commercial material collected and systematized by the offshore fields of Azerbaijan, the article discusses the reasons for the varying degrees of use of their reserves. For this purpose, the identification of deposits was carried out accord- ing to the natural regime, as a complex factor affecting oil recovery. Oil recovery models have been obtained for offshore reservoirs, draining mainly in two types of mechanisms: mixed and solution gas drives. Based on these regression equations and geological-economical analysis, a comparative analysis of the factors influencing oil recovery was carried out. Study of the different nature of the implementation of reserves of deposits characterized by different natural mechanisms so as to determine the degree to which the geological and technological parameters at various stages of development influence oil recovery. Objects: Offshore deposits of the Republic, characterized mainly by the solution gas and mixed drives. Application of the methods of mathematical statistics (Student’s and Fisher’s criteria) for the comparative analysis of the parameters of the mined deposits, confined to different natural conditions, allowing the revelation of the degree to which they are different and various patterns of the use of the reserves. In order to determine the influence of various factors on oil recovery, we used the method of correlation-regression analysis. It was found that a wide range of changes in oil recovery factors is associated with the internal structure of the deposits, with varying degrees of activity of the energy of the reservoirs and the fluids saturating them. It is known that each of the geological and technolog- ical parameters to one degree or another affects oil recovery, this influence is complex and subject to certain changes in the process of reservoir mining. In order to study the influence of parameters on oil recovery, we developed matrices of averaged values of a number of parameters of offshore deposits draining by mixed and solution gas drives. Using multivariate correlation-regression analysis and appropriate software, we obtained models for each of the above types of the mechanisms. A comparative analysis of those models, as well as geological and field studies of the parameters included in the obtained regression equations, make it possible to correct the oil production process in a timely manner, and can also be used in designing projects for the additional mining of those objects.
 
 

Evaluating the role of salts on emulsion properties during water-based enhanced oil recovery: Ion type, concentration, and water content

Potential determining ions (SO42−, Mg2+, Na, and Ca2+) positively affect oil recovery. These ions can cause changes in the oil and water system due to their ionic radius and proper charge density. Besides the type of ions, the concentration of these ions is also important. In order to maximize oil recovery, the concentration of these active ions should be at a level that pulls the polar components of the oil towards the oil–water interface and causes the interfacial tension to decrease, resulting in a decrease in capillary force and an increase in oil recovery. In some cases, the presence of various ions in the formation water or injection water provides the conditions for the formation and stability of the emulsion. Emulsion formation sometimes reduces production and sometimes improves production from oil reservoirs. Therefore, it is imperative to study the effects of ions on the formation, stability, and viscosity of emulsions. Regarding the emulsion stability in the presence of different ions, there are high uncertainties, and there is no uniform opinion on this matter. In this study, MgCl2, CaCl2, NaCl, and Na2SO4 were used to investigate emulsion properties. Droplet size and viscosity were measured using an optical microscope and a rolling ball viscometer, respectively, in order to determine emulsion stability. The results have shown that salts with higher positive charge density, such as MgCl2 and CaCl2 can significantly reduce the size of emulsion droplets and increase emulsion stability. Moreover, the presence of divalent anions such as sulfate reduces the amount of asphaltene at the interface between oil and water, thereby reducing the stability of the emulsion. In the order of MgCl2 > CaCl2 > Na2SO4 > NaCl, salts decreased the droplet size and increased the emulsion stability. The viscosity of the emulsion also showed a similar trend, as the average particle size decreases, the viscosity of the emulsion increases. Based on the results, the size of the emulsion droplets decreases up to a certain concentration and then increases. In the case of all salts, this concentration was equal to 10,000 ppm. The viscosity of the emulsion shows an increasing trend up to the concentration of 10,000 ppm, and after this concentration, it shows a decreasing trend. Salt-in and salt-out effects are responsible for the reduction and increase in droplet size. This study can provide insight into the effect of different ions on the stability and viscosity of the emulsion, as well as the design of the injection fluid for the enhanced oil recovery process.

Gel-Forming and Plugging Performance Evaluation of Emulsion Polymer Crosslinking System in Fractured Carbonate Rock

The water channeling of fractured carbonate rock seriously affects oil recovery, and this problem is especially serious in the Kazakh North Troyes oilfield. A conventional powder polymer plugging system needs to be hydrated ahead of time, which increases the cost and difficulty of field operation and it cannot realize large-scale plugging operations. The new emulsion polymer crosslinked system can realize rapid hydration and real-time mixing, having low base liquid viscosity and good fluidity and injectability. The results of the laboratory study show that the gelling time of HR9806 emulsion polymer and organic chromium crosslinker was 6~8 h. 0.5 wt % HR9806, which is recommended for field use with P/C ranging from 2.5 to 5.0. The emulsion polymer crosslinking system was found to be highly adaptable in reservoirs and had salinity resistance. Mineral salt and reservoir core were able to enhance the gel strength of the system but shortened the gelling time of the system by about 2 h. The gel (HR9806) had good shear resistance. It still had a viscosity of 220 mPa·s under high-speed shearing (Temperature = 54 °C), and the formed gel system shear resistance increased with increasing concentration. The emulsion system of “0.50 wt % HR9806 emulsion polymer + 0.15 wt % organic chromium crosslinker + brine” had a strong plugging effect in the fractured core and sand-filled pipe model, with residual resistance coefficient ≥30, effective plugging rate ≥ 95.0%, and oil–water selectivity of 0.45. In this paper, the levels of weak gel strength were used, providing an experimental and theoretical reference for improving the application effect of the weak gel system in the field. The study found that the weak gel system can better enter the fractured carbonate reservoir and form a plugging effect in the fracture, improving the effect of subsequent water flooding matrix oil recovery.