Higher Oil Recovery Research Articles

Numerical Modeling and Simulation of Fractured-Vuggy Reservoirs Based on Field Outcrops

We propose a novel workflow to investigate the complex flow behaviors and remaining oil distribution related to the oil–gas–water three-phase system based on information from typical outcrops of fractured-vuggy reservoirs. A refined geological model is built to represent the size, geometry, and spatial distribution of the karst caves and fractures extracted from the field outcrop photographs. The combination of the perpendicular bisector (PEBI) grid technique and the control-volume finite difference method is adopted for space discretization. We have validated the numerical model against experimental data. Numerical simulations were performed to explore the impacts of the permeability of karst cave and natural fractures and the position of natural water bodies upon oil production performance. Numerical results indicate that (1) the cave permeability has few impacts on the oil production, yet the fracture permeability plays a significant role in determining the oil recovery; (2) a higher permeability of the fractures will lead to a longer period of time for no-water oil production and, thus, a higher oil recovery; (3) the position of natural water body shows significant impacts on oil recovery, e.g., a short distance between the natural water body and the production well tends to form preferential passages, causing severe reduction of water flooding range; and (4) the distribution of remaining oil is controlled by spatial patterns of the fractured-vuggy system and reservoir development schemes. We found that the remaining oil is mainly distributed along the model boundaries and at the corner of the caves with single or multiple connection/s to fractures.

Combination of Dehydration and Expeller as a Novel Methodology for the Production of Olive Oil.

An alternative olive oil (OO) production process has been developed based on the combination of olive dehydration, followed by extraction with an expeller press. This procedure eliminates the utilization of water and avoids the malaxation stage. Hence, no water residues are generated. In this study, the mentioned alternative methodology was compared to conventional extraction methods. High extraction yields and oil recovery were obtained with our novel procedure. On the contrary, substantial percentages of by-products were generated with conventional methodology. The quality indexes (acidity and peroxide values) of the oils obtained by the combination of dehydration and expeller (dOO) were 0.4% of oleic acid and 3 meq O2/kg of oil, respectively. Furthermore, none of the applied processes affected the resulting OO's fatty acid composition and lipid profile. Total phenolic content was up to four times higher for dOO than for other olive oils and it showed resistance to oxidation with an oxidative stability index about five times higher than that for conventional olive oils.

Alternative stable microbiome state triggered by the introduction of functional microbes in oil reservoirs drives sustainable microbial enhanced oil recovery

Microbial enhanced oil recovery (MEOR) is a promising substitute for other enhanced oil recovery methods in terms of sustainable development. However, the response mechanism of the microbial community to the introduction of functional microbes remains unclear, which limits MEOR strategic planning to achieve a long-term effect. In this study, we reveal the existence of alternative stable states in an oil reservoir for the first time and examine the correlation between the microbiota status and the oil production increment. There existed a basal state A and alternative state B in the reservoir microbial community, and this resulted in a differential microbial oil displacement effect. The oil production increased by up to 50% in basal state A, because Halomonas dominated most niches and restrained other functional microbes. The introduction of biosurfactant-producing bacteria triggered the microbiota status to shift to the alternative state B associated with higher oil recovery. In state B, the high microbial diversity and positive interaction among Dietzia, Bacillus and other species significantly activated the effectiveness of the microbial oil displacing function. Due to the hysteresis of the microbial community, it required frequent and intensive introduction of functional microbes to improve the microbiota in the reservoir and sustainably promote oil recovery. Overall, this study provides new insights into the response mechanism of the microbial community to the introduction of functional microbes in an oil reservoir. This study also provides guidance for effective management of a MEOR strategy to achieve sustainably enhanced oil production.

The impacts of CO2 flooding on crude oil stability and recovery performance

Numerous studies have investigated the fundamental mechanisms by which CO2 flooding can increase oil production by altering the properties of the hydrocarbon fluid, including oil swelling, viscosity and interfacial tension reductions, and the extraction of light-to-intermediate components. However, the interactions between CO2 and hydrocarbon fluid may also cause several problems, such as asphaltene precipitation due to crude oil's instability during the CO2 flooding process. This study investigates the complex factors that affect the instability of crude oil, including CO2 injection pressures, temperatures, and crude oil compositions. The light-dead oil samples taken from two Indonesian oil fields were used. The impacts of the instability of crude oil on CO2 displacement performance were also observed to evaluate oil recovery and minimum miscibility pressure (MMP). The observation was performed using a slim tube under varying CO2 high-pressure injections at 90 °C and 70 °C. The produced oils were analyzed based on their polarity component, saturates, aromatics, resins, and asphaltenes fractions, to observe the changes in oil composition and colloidal index instability. The results showed that increasing temperatures at given pressures resulted in higher oil recovery. Moreover, the asphaltene and resin fractions in the oil produced at a lower temperature significantly decrease compared to those at a higher temperature. It was also shown that asphaltene tends to precipitate more easily at a lower temperature. The other phenomenon revealed that the lighter oil resulted in a lower recovery than the heavier oil at a given pressure and temperature and correspondingly higher MMP. It was also suggested that CO2 flooding is more likely to cause asphaltene precipitation in light oils.

Screening of Chemicals to Enhance Oil Recovery in a Mature Sandstone Oilfield in Kazakhstan: Overcoming Challenges of High Residual Oil

Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A.

Numerical Simulation Study of Steam Injection Optimization in Shallow Reservoir

In an EOR project, process improvement must be continually pursued since EOR is often marginally profitable. In steamflood EOR project, steam injection rate is very important parameter to ensure that each pattern reach maturity within a certain early period that result in high oil recovery and meet the economic hurdles. In particularly shallow formation settings, steam injection target is often difficult to achieve because limited by fracturing pressure to avoid breaching the cap rock and creating environmental problem. In this study we simulate steam injection in a typical heavy oil reservoir (high API, shallow depth, low pressure) to enable optimization of steam injection. A model has been built using typical shallow reservoir in using Builder-CMG. Wellan data, fluid model and operating conditions (injection strategy, steam quality) and expected/ forecasted performance. CMOST package is then used to design optimization study by varying the steam injection rate. The best scenario is based on the lowest reservoir pressure and cumulative SOR. We created three development options: regular inverted 7-spot 15.5-acre pattern, horizontal well and pattern size reduction (PSR). From this numerical study it is found that for the case studied, steam injection rate can be ramped up from 250 - 300 BSPD within 6-7 years, followed by peak production. A wind down injection rate to 0 can be used after this peak production to achieve CSOR target of 3-4 bbl of steam/bbl of oil. If a quicker SBT is required, then more steam injectivity is needed to put underground. Several scenarios can be considered as follow: (1) reducing the pattern size (thus adding steam via additional injection wells) and (2) utilizing horizontal wells.

Hydraulic Cold-Pressed Extraction of Sacha Inchi Seeds: Oil Yield and Its Physicochemical Properties

Sacha inchi oil (SIO) extraction has been extensively studied using various oil extraction techniques to achieve a high oil recovery. However, most studies relied on heat-based methods, which led to compromised oil quality and reduced nutritional values, particularly polyunsaturated fatty acids (omega-3 and omega-6), vitamin E, and phenolic compounds. To address these concerns, this study employed a hydraulic cold-pressed extraction (HCPE) technique for extracting SIO aiming to enhance oil yield while preserving its nutritional integrity. During the HCPE process of sacha inchi seeds (SIS), conducted at a constant temperature of 25 ± 1 °C, pressures and pressing times were varied within the range of 30–50 MPa and 10–30 min, respectively, to determine their impact on SIO yields. The results revealed that both pressure and pressing time significantly influenced the yields of SIO (p < 0.05), with the highest oil recovery of 86.31 wt.% on a wet basis achieved at 50 MPa for 30 min. Regarding physicochemical properties, the peroxide values (5.71–9.07 meq/kg), iodine values (176.22–197.76 g I2/100 g), acid values (1.82–2.16 mg KOH/g), and percentage of free fatty acids (0.91–1.08 wt.% as oleic acid) were found to be influenced by pressure and pressing time (p < 0.05). Additionally, the color variation by L* (34.22–35.17), −a* (0.39–0.81), and b* (3.48–5.62) changed with each oil yield. Notably, the high iodine value in SIO indicated a substantial content of polyunsaturated fatty acids, including omega-3 (40.86%), omega-6 (40.87%), and omega-9 (10.20%). Furthermore, a comparison with solvent extraction methods demonstrated that HCPE exhibited similar efficiency in extracting SIO, offering additional advantage in terms of its cold-pressed condition, eliminating of solvent use, simplicity, short extraction time, and higher oil recovery.

Investigating the impact of wettability heterogeneity on tertiary oil recovery by foam flooding: A macroscopic visualization study

The gas injection is a widely used technique for improving oil recovery; however, in reservoirs with heterogeneous characteristics, the injection of gas in the form of foam is more promising. Due to the heterogeneous nature of oil reservoirs, we compared the foam flow performance at the tertiary mode with that of gas injection using an anionic surfactant AOS and a cationic surfactant CTAB. Glass bead packed models were used with different patterns of wettability heterogeneity including oil-wet, water-wet, stripe, layer, and quadrant. While gas injection in heterogeneous models produced only 10–15% of the waterflood residual oil, foam injection could control the gas mobility and recover almost 30–50% of the residual oil. The most stable foam was formed in the water-wet porous medium whereas the lowest stable foam was visually observed in the oil-wet porous medium due to the presence of more residual oil. However, the synergistic effect of wettability alteration and piston-wise displacement of the foam front improved oil recovery even in the oil-wet medium compared to the gas injection scenarios. Among all heterogeneous models, the highest oil recovery was achieved in the layer model and its oil recovery profile was compatible with that of the water-wet homogeneous model. Conversely, we found that positioning an oil-wet layer strongly declined foam flow performance as was observed in both layer and quadrant models. Compared to the AOS foam, the CTAB foam was more stable and efficient in recovering waterflood residual oil in the models under study.

Efekty lepkosprężyste w warunkach nawadniania kolektora szczelinowo-porowego cieczą wodno-polimerową

The work is devoted to the numerical simulation of the flow of simple and viscoelastic (polymer solution) fluids through a fracture by using polymer solutions for enhanced oil recovery from a reservoir. Polymer solutions have viscoelastic properties. Therefore, when polymer solution flows through the slot, we use the well-known Maxwell’s fluid model with the Jaumann derivative to evaluate deformation characteristics of the flow (stream functions, distributions of the longitudinal velocity gradient and normal stress) resulting in the manifestation of abnormal (compared with the behaviour of the ordinary fluid) effects. The case of slow flow is considered. In this case, the inertial terms can be neglected, the velocities, stresses, and stream functions can be written as the decomposition by Weisenberg number, and we can assume that the Weissenberg number is less than one. The determined regularities of viscoelastic (polymer solution) liquid behaviour with longitudinal velocity gradient and the elastic deformations effects manifested in this case have a decisive meaning in understanding the mechanism of anomalously high oil recovery capacity of a reservoir by using water-polymer flooding of the fractured-porous reservoir. Understanding the nature of the effects of elastic deformations under the conditions of water-polymer flooding of the fractured-porous reservoir enables hydrodynamic calculations of the optimal flow of the polymer solution. One of the main issues that need to be solved when developing the technology for increasing oil recovery from formations using polymer solutions is to determine the optimal flow regime in the fractured-porous reservoir. The calculation results verify the ideas obtained from the experimental solution of this problem concerning the strain-stress state of polymer macromolecules (liquid elements) during polymer flow in the inlet area of the fracture in the oil reservoir and confirm the possibility of using numerical analysis of convergent polymer flow for calculating longitudinal velocity gradients in the inlet area of the fracture and can also serve as additional substantiation of the proposed earlier mechanism for increasing oil recovery from reservoirs by using polymer solutions.

Effect of CO2 Huff-n-Puff Mode with a Horizontal Well on Shale Oil Recovery: A Three-Dimensional Experimental Study

After conventional development, there is still a significant amount of residual oil as a result of the poor porosity and permeability characteristics of shale reservoirs. Although CO2 flooding is one of the most reasonable recovery techniques, it is affected by a serious sweep efficiency issue. In this paper, six CO2 huff-n-puff cooperative combination methods were established with the aid of three-dimensional physical simulation equipment, including CO2 huff-n-puff (HNP), water-disturbance-assisted CO2 huff-n-puff (WD-HNP), surfactant- and water-disturbance-assisted CO2 huff-n-puff (SWD-HNP), pumping-production-assisted CO2 huff-n-puff (PP-HNP), water-disturbance-assisted CO2 huff-n-puff after pumping production (WDP-HNP), and surfactant- and water-disturbance-assisted CO2 huff-n-puff after pumping production (SWDP-HNP). The displacement characteristics, utilization law, and development effect were investigated. CO2 huff-n-puff requires more gas injection quickly, and low permeability and pressure difference can easily cause irregular gas channeling, showing the arc linear flooding pattern. Water disturbance can significantly delay the rapid breakthrough, so that the displacement edge shows the radial flooding pattern. The effect of pumping production on the displacement is not obvious, and the leading edge still shows an oval-shaped flooding pattern. Surfactant assistance improves the gas injection ability, eventually demonstrating a plane steady flooding pattern. In comparison to HNP, the average enhancement degree of water injection disturbance, pumping production, and surfactant assistance to the utilization extent is 6.61, 1.82, and 8.93% respectively. Meanwhile, SWDP-HNP had the highest oil recovery (33.35%) among all modes. By comparison of effective productivity, it revealed that about 12% of the lifting range is helped by surfactant assistance, followed by a water injection disturbance lifting amplitude of 5.5%, while pumping production only led to a 3% improvement. With the combination of all development effect evaluation indicators, SWD-HNP is a reasonable displacement method to improve shale reservoir recovery in this study.

Simulation study of polymer flooding performance: Effect of salinity, polymer concentration in the Malay Basin

The major problem of the water flooding development process is the flood process's high mobility and viscous fingering. Previous studies have shown that polymer flooding is viable and can recover bypassed oil. However, the mechanism of the polymer flooding process is still tenuous in literature. Therefore, in this study, a two-dimensional model was used to simulate polymer flooding and forecast the mechanism of the polymer flood in the presence of electrolytes. Likewise, the effect of pH, pressure, and temperature on the polymer flooding process was investigated. Thereafter, the model was validated with an independent set of experimental data from the literature. The results show that the polymer flooding mobility ratio (M) was 0.36 indicating a favorable mobility control, thereby improving oil recovery by 60% of original oil in place (OOIP). In comparison, to water flooding mobility ratio of 3.6, which was greater than 1, thus resulted in viscous fingering, early water breakthrough, and oil recovery of 36% OOIP. Besides, at high salinity concentrations, the polymer adsorption was 3.3 mg/g compared to 2.2 mg/g from the experimental results. This indicates that the simulation results were consistent with the experimental results at the same concentration. Likewise, the simulation and experimental studies suggest high oil recovery was obtained at a higher injected pore volume. Finally, it can be concluded from this study that mechanical trapping and adsorption of the polymer on the pores of the porous media were the dominant mechanisms during the polymer flooding.

Rock wettability and interfacial tension improvement by exposure time effect in modified water injection process coupled with silica nanoparticles

New approaches to low salinity water (LSW) injection methods, such as LSW/surfactant, LSW/polymer, and LSW/nanofluid flooding, have been studied for oil reservoirs. Numerous researchers discussed the mechanisms related to enhanced oil recovery (EOR) efficiency and highlighted the significant impact of the wettability alteration and interfacial tension (IFT) reduction. This work studied the effect of exposure time on the wettability alteration and IFT in the LSW/nanoparticle (LSWN) flooding. Contact angle tests investigated rock wettability over a series of different times. A pendant drop tensiometer was used to measure the IFT. By coreflood apparatus, waterflood tests were also conducted, considering the effect of soaking time. Laboratory results showed that the involved mechanisms are time-dependent. More water-wet conditions and higher oil recovery were obtained under longer soaking time. In addition, the positive effect of LSWN was observed in tertiary flooding tests. The results also indicate that the effect of water-soluble oil compounds should be considered in measuring wettability and IFT.

Review on Potential Application of Saponin-Based Natural Surfactants for Green Chemical Enhanced Oil Recovery: Perspectives and Progresses

Synthetic chemical surfactants deployed in the petroleum industry to improve oil recovery to meet growing global energy demand are described to have detrimental environmental impacts and are expensive. In recent times, the exploration of saponin-rich plants as a substitute for environmentally threatening synthetic surfactants has garnered significant interest from researchers. Saponin-based natural surfactants (SBNSs) are nontoxic, biodegradable, and possess desirable properties for use in the oil and gas industry. This paper reviews the potential application of saponin-based natural surfactants in enhanced oil recovery processes that coincide with the interests of the United Nations’ Sustainable Development Goal 7 for Affordable and Clean Energy. We reviewed the mechanisms of saponin-based natural surfactants in enhanced oil recovery (EOR), surfactant adsorption, and the recent advances in utilizing saponin-based natural surfactants for EOR purposes. We also provided a comprehensive analysis of the impact of salinity and temperature on the performance of SBNSs. Moreover, the study also presented the economic feasibility and limitations of SBNSs for field enhanced oil recovery applications. We identified that a good number of SBNSs can withstand harsh reservoir conditions, optimize interfacial tension by as high as 95.82% (although not to ultralow levels), and alter rock wettability from hydrophobicity to hydrophilicity, thereby reducing the contact angle by 3.64% to 87.5%. SBNSs also successfully yielded a high incremental oil recovery factor of up to 36% in the postsecondary recovery stage. The advent of techniques, such as alkali incorporation and nanotechnology, support the achievement of ultralow interfacial tension, mitigation of surfactant adsorption, and oil recovery improvement. Future studies can adopt the recommendations outlined in this study to minimize uncertainty in the utilization of SBNSs and enhance their design for “green” chemical enhanced oil recovery applications.

Experimental study on the plugging and profile control of preformed particle gels in high temperature and salinity reservoir

AbstractA novel modified polysaccharide composite preformed particle gel (MCPG) was synthesized as a profile control agent to improve the situation of high water cut and low oil recovery. Then, the structure of MCPG was characterized by Fourier transform infrared spectroscopy (FTIR), X‐ray diffraction (XRD), and environmental scanning electron microscope (ESEM). Subsequently, the impact of MCPG on enhanced oil recovery was investigated through nuclear magnetic resonance (NMR) and core displacement experiments. The results of FTIR, XRD, and ESEM indicate that monomers have been successfully intercalated into the layered structure of nanoscale sodium bentonite. In the condition of 130°C and salinity of 240,000 mg/L, the value of the swelling ratio and the toughness factor can reach about 30 and 0.87, respectively. The results of nonlinear fitting indicate that the relationship between the resistance coefficient and residual resistance coefficient with the matching coefficient (β) followed a power function, while the blocking water efficiency with β followed an exponential function. When the permeability ratio was as high as 30.58, MCPG still exhibited excellent profile improvement performance. NMR experiments proved that MCPG increased the displacement resistance in large pores and effectively enhanced the displacement efficiency in medium pores and small pores. The oil displacement efficiency in MCPG flooding and subsequent water flooding stages increased by 18.65% and 8.42%, respectively.

Mechanism of enhanced oil recovery of ultra-dry CO2-in-water foams in porous media: Experiments and numerical simulation

The application of ultra-dry CO2 foam in enhanced oil recovery (EOR) accelerates recovery and enables CO2 utilization and sequestration. The flow characteristics of foam in porous media play a crucial role in the foam EOR process. Herein, ultra-dry CO2-in-water (C/W) foam with 10% water was prepared at 80 °C and 12 MPa using cocamidopropyl betaine (CAPB) and nonionic polyacrylamide (NPAM). Additionally, the constitutive equation for the foam fluid was determined by flow experiments using tubes with different diameters. The CO2 foam was a shear-thinning, non-Newtonian fluid and conformed to the Herschel–Bulkley (H–B) model. The core displacement experiment with the permeability of 470 mD showed that the oil recovery of foam flooding increased from 56.01% of water flooding to 76.01% at the same temperature and pressure. The maximum pressure difference rose sharply from 0.48 MPa of water flooding to 1.2 MPa of foam flooding, increasing by 2.5 times; the pressure difference finally stabilized at 0.64 MPa, which was approximately 4.3 times that of water flooding. Moreover, a two-dimensional (2D) model of the porous media was constructed using digital core technology. Using the validated model, sensitivity analysis based on the phase-field method (PFM) was performed to investigate the effect of different power-law exponents on displacement. The results indicate that increasing the power-law exponent of the foam fluid slowed down breakthrough and improved the sweep efficiency, resulting in higher oil recovery.

Robust 3D porous superhydrophobic foam with excellent photothermal effect and Joule heating effect for efficient all-weather cleanup of highly viscous crude oil spills

Crude oil spill is difficult to deal with and still a global challenge due to its high viscosity. Developing foams with excellent mechanical properties, photothermal effect and Joule heating effect simultaneously to achieve crude oil all-weather recovery is desirable. Here, 3D porous foams were successfully fabricated by the composite of polydimethylsiloxane (PDMS) and multi-walled carbon nanotubes (MWCNT) by a combination of sacrificial template method and laser etching treatment. Benefiting from the low surface energy of PDMS itself and the micro-nano structures constructed in the preparation, the obtained foams exhibit excellent superhydrophobic and superoleophilic properties (WCA of 157° and OCA of 0°). Significantly, MWCNT do not exist as a coating around the foam surface, but as the main component constituting the foam skeleton, so the foam shows excellent mechanical property, low temperature resistance, high temperature resistance, salt resistance and abrasion resistance. Moreover, taking the advantage of the addition of MWCNT, the foam shows excellent photothermal effect requiring 1 sun irradiation to attain a temperature of 60.7 ℃ after 4 min and a stable temperature of 71.6 ℃ after 10 min, and Joule heating effect requiring only 9 V voltage to attain a temperature of 64.5 ℃ after 1.5 min and a stable temperature of 91.1 ℃ after 10 min, respectively. Besides low viscosity oil–water separation, it can achieve rapid crude oil spill recovery under the photothermal effect or Joule heating effect. The combination of the two effects can realize the coupling effect and achieve high-efficiency all-weather high viscosity crude oil recovery, thus making the foam more practical. This foam is expected to be an ideal material for all-weather dealing with oil spills.

Remaining Oil Distribution Law and Development Potential Analysis after Polymer Flooding Based on Reservoir Architecture in Daqing Oilfield, China.

Polymer flooding has drawn more and more attention in the world for its high incremental oil recovery factor and relative low costs compared with water flooding and other chemically enhanced oil recovery techniques. However, for many oilfields, such as Daqing Oilfield, China, that have already been flooded with polymers, how to further improve recovery remains a big problem. Traditional intralayer, interlayer and plane heterogeneity studies cannot accurately characterize the remaining oil distribution after polymer flooding. To solve this problem, we established a method to quantitatively describe the reservoir's architecture. Then, the architecture elements were dissected hierarchically and the interface of each architecture level in Daqing Oilfield was identified. The distribution pattern and development potential of the remaining oil after polymer flooding under the influence of reservoir architecture was analyzed. The results show that, regarding the sedimentary process from north to south in Daqing Oilfield, the channel becomes narrower, the thickness decreases, the point bar's width increases and the thickness of the meandering river decreases. The braided bar scale becomes larger and the thickness becomes smaller in the braided river. According to the reservoir's architecture, the remaining oil was divided into four categories of plane remaining oil (abandoned channel occlusion type, interfluvial sand body occlusion type, inter-well retention type and well pattern uncontrollable type) and three types of vertical remaining oil (in-layer interlayer occlusion type, rhythm type and gravity type). About 40% of the original oil in place (OOIP) of Daqing Oilfield has not yet been produced, which indicates that there is great potential for development. This study is important for improving oil recovery in polymer-flooded reservoirs.

The Effect of Nano Heavy Metal Oxide Particles on the Wettability of Carbonate Reservoir Rock

Summary Production of oil from carbonate rocks is very challenging due to their inherent nature, such as detection, complex wettability, pore structure, and low recovery factor. Nanoparticles (NPs) are recognized as remarkable materials for a wide range of research and commercial applications due to their physical properties and characteristics. Extensive research in recent years has shown that nanoscience can provide great potential for the development of carbonate reservoirs and enhanced oil recovery (EOR). In this study, the carbonate core plug samples were prepared from an Iranian reservoir. At first, the wettability capacity of the core samples was evaluated. This process was carried out by evaluating wettability changes using the contact angle of base fluid and nanofluid. The potential of the NPs (ZnO, TiO2, and ZrO2) to change the wettability was experimentally tested in the loading NPs from 0.01 wt% to 0.5 wt% by the contact angle method. Wettability studies have shown that nanofluids can influence wettability variability from oil-wet to water-wet quality. About 0.05 wt% of NPs was found to be the optimal concentration to affect wettability change. The same behavior was observed for all nanofluids at the same NP loading; while TiO2 showed better performance with a sharp change from an oil-wet state (θ = 151.9°) to a water-wet state (θ = 111.3°), ZnO, and ZrO2 changed wettability to a moderately-wet condition (θ = 108.6° and 118.6°, respectively) at 0.05 wt% NP loading. We conclude that TiO2-based nanofluids have great potential as EOR agents, and TiO2 is very impressive in its strong water-wettability. The highest oil recovery in the optimal amount for all three nanofluids was obtained as 35.2%, 23.2%, and 25.6%, respectively, for TiO2, ZnO, and ZrO2 nanofluids. Furthermore, we considered the effect of nanofluids on the recovery performance of the brine/oil system for carbonate core samples. The results showed that nanofluids can significantly imbibe into the core sample, and as a result, the final oil recovery is significant.

WAG injection in porous media: A microfluidic analysis

Water Alternating Gas (WAG) injection is one of the common methods to displace oil in porous media, which is relevant to many applications including soil remediation or enhanced oil recovery from underground reservoirs. We conducted a comprehensive series of experiments to extend the fundamental understanding of WAG injection in porous media. Three types of porous media were manufactured with a 3D printer in this investigation. The first medium had single permeability (S), the second one was fractured (F), and the third one was a medium with dual permeability (D). The porous media were saturated with silicone oil. Nitrogen and water were used to displace oil under different WAG ratios of 4:1, 2:1, 1:1, 1:2, and 1:4. High-resolution imaging was used to quantify displacement dynamics. The highest oil recovery was observed under WAG ratio of 1:1, i.e., the equal slug size of the water and gas. The obtained results showed that the WAG ratio of 1:1 injection in the S medium recovered 55% of the oil, while in the F and D medium, the recovery efficiency was 36% and 47%, respectively. Our findings offer new insights regarding effects of heterogeneity on WAG injection efficiency in porous media under different boundary conditions.

Investigation of the Coupled Effect of IFT Reduction and Wettability Alteration for Oil Recovery: New Insights.

Interfacial tension (IFT) reduction and wettability alteration (WA) are both important enhanced oil recovery (EOR) mechanisms. In oil-wet formations, IFT reduction reduces the magnitude of negative capillary pressure, releasing trapped oil. WA changes the negative capillary pressure to positive conditions, helping the entrance of the aqueous phase, and the displacement of the oil phase. In most cases, IFT reduction and WA happen at the same time. However, studies regarding the coupled effect provided different, sometimes conflicting observations. It requires further study and better understanding. In our study, oil-aged Indiana limestone samples were chosen to represent oil-wet carbonate rocks. Static contact angle and spinning drop method were adopted for wettability assessment and IFT measurement, respectively. Spontaneous imbibition was adopted to reflect on the oil recovery mechanisms in different cases. The impact of IFT reduction, WA, and permeability on the coupled effect was discussed by choosing four pairs of comparison tests. Results showed that when the coupled effect took place, both a higher IFT value and a stronger WA performance resulted in faster and higher oil recoveries. The importance of IFT reduction was enhanced in the higher-permeability condition, while the importance of WA was enhanced in the lower-permeability condition.