Core Displacement Experiments Research Articles

Preparation and Effect of CO2 Response Gel for Plugging Low-Permeability Reservoirs

In order to solve the problem of gas channeling during CO2 flooding in low-permeability reservoirs, a novel CO2 responsive gel channeling system was prepared by using carrageenan, branched polyethylene imide and ethylenediamine under laboratory conditions. Based on the Box–Behnken response surface design method, the optimal synthesis concentration of the system was 0.5 wt% carrageenan, 2.5 wt% branchized polyethylenimide and 6.5 wt% ethylenediamine. The micromorphology of the system before and after response was characterized by scanning electron microscopy. The rheology and dehydration rate were tested under different conditions. The channeling performance and enhanced oil recovery effect of the gel system were simulated by a core displacement experiment. The experimental results show that the internal structure of the system changes from a disordered, smooth and loosely separated lamellae structure to a more uniform, complete and orderly three-dimensional network structure after exposure to CO2. The viscosity of the system was similar to aqueous solution before contact with CO2 and showed viscoelastic solid properties after contact with CO2. The experiment employing dehydration rates at different temperatures showed that the internal structure of the gel would change at a high temperature, but the gel system had a certain self-healing ability. The results of the displacement experiment show that the plugging rate of the gel system is stable at 85.32% after CO2 contact, and the recovery rate is increased by 17.06%, which provides an important guide for the development of low-permeability reservoirs.

A study on the emulsification ability and oil displacement efficiency of polymeric surfactant in porous media

In order to comprehensively comprehend the distinctions in solution properties, emulsification characteristics, and oil displacement efficiency between polymeric surfactant(DG-1) and traditional polymers or surfactants, a comparative analysis was initially conducted on the microstructure, main functional group types, and macroscopic properties. Subsequently, core displacement experiments were employed to elucidate the emulsification capability, emulsion stability, and oil displacement properties of polymeric surfactants. The microscopic displacement experiment was ultimately conducted to investigate the residual oil displacement process in the core following polymer displacement by DG-1, thereby elucidating the underlying mechanisms of microscopic oil displacement by DG-1. The results indicate DG-1 has a molecular structure with a regional network aggregation state as a whole, and a multi-layer aggregation and overlapping structure in space. DG-1exhibits higher viscosity and lower interfacial tension due to the larger molecular coil dimension compared to the equivalent concentration of polymers. The emulsification ability of DG-1 is robust, with emulsion stability positively correlated to oil-polymer ratio and concentration while negatively correlated to migration distance. Core displacement experiments results indicate the polymer-surfactant system (SP) and DG-1 exhibited comparable oil displacement effects, with oil recovery of 54.5% and 52.4%, respectively, both surpassing the recovery achieved by the polymer alone (46.9%). In heterogeneous reservoirs, SP acts as the dominant displacer in regions with moderate and high permeability, whereas DG-1 assumes dominance in regions with moderate and low permeability. The microscopic displacement experiments revealed that DG-1 activated the clustered residual oil as the predominant type of residual oil in porous media, followed by columnar and block residual oil, with film residual oil exhibiting the least activation. Primary mechanisms for oil displacement include extended sweeping volume, shear and carrying effects on the residual oil, and eddy displacement of the residual oil by the emulsion.

Experimental Evaluation of Performance of a Low-Initial-Viscosity Gel Flooding System.

In order to effectively adjust reservoir heterogeneity and further exploit the remaining oil, a new type of low-viscosity gel was prepared by adding a regulating agent, retarder, and reinforcing agent on the basis of a polymer + Cr3+ crosslinking system. The new gel has the advantages of low initial viscosity, a slow gel formation rate, and high strength after gel formation. The effectiveness of the gel was verified through three-layer core displacement experiments, and the injection scheme was optimized by changing the slug combination of the polymer and the gel. The results showed that the gel can effectively block the high-permeability layer and adjust reservoir heterogeneity. An injection of 0.1 pore volume (PV) low-initial-viscosity gel can improve oil recovery by 5.10%. By changing the slug combination of the gel and polymer, oil recovery was further increased by 3.12% when using an injection of 0.07 PV low-initial-viscosity gel +0.2 PV high-concentration polymer +0.05 PV low-initial-viscosity gel +0.5 PV high-concentration polymer.

Long carbon chain-modified carbon nanoparticles for oil displacement in harsh-condition reservoirs

Carbon nanoparticles, as an emerging type of enhanced oil recovery agent, promising broad prospects in unconventional oil and gas development. However, limitations such as low interfacial activity due to the strong hydrophilicity of carbon nanoparticles and tendency to aggregate under high-temperature and high-salinity conditions restrict their further application. In this study, activity carbon dots (S-CDs) were prepared via a simple two-step hydrothermal reaction. A range of physicochemical techniques characterized S-CDs, revealing their small particle size (1.4 ± 0.01 nm) and narrow distribution, maintaining strong dispersion stability in mineralized water at 130 °C with a concentration of 16 × 104 mg/L. The AFM scanning results indicated that S-CDs possessed strong interfacial wetting control capability, the adhesion force between oil and rock cores (after S-CDs treatment) decreased by 25 times. Particle Image Velocimetry (PIV) confirmed that S-CD adsorbed at the oil-water interface could formed a solid film, which could rupture into smaller oil droplets for convenient backward migration. The results demonstrated that S-CDs improved the interfacial activity while maintaining the hydrophilicity of CDs. In core displacement experiments, 0.05 wt% S-CDs nanofluid reduced injection pressure by 32.4 % and increased recovery rates by 34.9 %. This work provides new insights for the development of high-temperature, high-salinity displacement agents in harsh-condition reservoirs.

Flooding Performance and Optimization of Injection Parameters of Nanosized Oil Displacement Agents in Extra-Low-Permeability Reservoirs.

There have been few studies on the role of nanofluids in oil displacement and injection parameters, despite their significant impact on the oil displacement effect. To enhance oil recovery in an ultralow-permeability reservoir, the nanosized oil-displacement agent with nano-SiO2 modified by a silane coupling agent as a main component was selected for the first time in the Changqing oilfield. To assess the performance of the nanofluid, various factors such as particle size, contact angle, interfacial tension, and emulsion stability were taken into consideration. The oil displacement effect of nanofluids was evaluated by a microscopic model and ultralow-permeability core displacement experiment, and its optimal injection parameters were determined. The average particle size of the nano-oil displacement agent is 22-30 nm. It can change the wetting condition of the rock from oil-wet to water-wet and reduce the oil-water interfacial tension. Even at 80 °C, the emulsion formed by the agent remained stable. The oil displacement experiment shows that the nano-oil displacement agent whose injection pressure increases can displace the residual oil trapped in small pores that cannot be affected by conventional water flooding. The injection mode of "nanoflooding agent drive + water drive + nanoflooding agent drive", injection rate of 0.1 mL/min, injection concentration of 0.5%, and injection volume of 0.5 PV (0.25 PV per segment), which can effectively guide the injection of the oil displacement agent, achieve the best oil displacement effect.

Fine quantitative characterization of high-H2S gas reservoirs under the influence of liquid sulfur deposition and adsorption

In order to clarify the influence of liquid sulfur deposition and adsorption to high-H2S gas reservoirs, three types of natural cores with typical carbonate pore structures were selected for high-temperature and high-pressure core displacement experiments. Fine quantitative characterization of the cores in three steady states (original, after sulfur injection, and after gas flooding) was carried out using the nuclear magnetic resonance (NMR) transverse relaxation time spectrum and imaging, X-ray computer tomography (CT) of full-diameter cores, basic physical property testing, and field emission scanning electron microscopy imaging. The loss of pore volume caused by sulfur deposition and adsorption mainly comes from the medium and large pores with sizes bigger than 1 000 μm. Liquid sulfur has a stronger adsorption and deposition ability in smaller pore spaces, and causes greater damage to reservoirs with poor original pore structures. The pore structure of the three types of carbonate reservoirs shows multiple fractal characteristics. The worse the pore structure, the greater the change of internal pore distribution caused by liquid sulfur deposition and adsorption, and the stronger the heterogeneity. Liquid sulfur deposition and adsorption change the pore size distribution, pore connectivity, and heterogeneity of the rock, which further changes the physical properties of the reservoir. After sulfur injection and gas flooding, the permeability of Type I reservoirs with good physical properties decreased by 16%, and that of Types II and III reservoirs with poor physical properties decreased by 90% or more, suggesting an extremely high damage. This indicates that the worse the initial physical properties, the greater the damage of liquid sulfur deposition and adsorption. Liquid sulfur is adsorbed and deposited in different types of pore space in the forms of flocculence, cobweb, or retinitis, causing different changes in the pore structure and physical property of the reservoir.

Experimental Study on the Mechanism and Law of Low-Salinity Water Flooding for Enhanced Oil Recovery in Tight Sandstone Reservoirs.

Currently, research surrounding low-salinity water flooding predominantly focuses on medium- to high-permeability sandstone reservoirs. Nevertheless, further investigation is necessary to implement this technique with regard to tight sandstone reservoirs. The present study comprises a series of experiments conducted on the crude oil and core of the Ordos Chang 6 reservoir to investigate the influence of ionic composition on low-salinity water flooding in tight oil reservoirs. The change in wettability on the rock surface was analyzed by using the contact angle experiment. The change in recovery rate was analyzed using a core displacement experiment. The reaction between rock fluids was analyzed using an ion chromatography experiment. Additionally, a nuclear magnetic resonance (NMR) experiment was used to analyze the mobilization law of crude oil and the change in wettability on the scale of the rock core. This led to a comprehensive discussion of the law and mechanism of enhancing the recovery rate via low-salinity water flooding from various perspectives. Experiments show that low-salinity water flooding is an effective technique for enhancing recovery in tight sandstone reservoirs. Altering the ionic composition of injected water can improve the water wettability of the rock surface and enhance recovery. Decreasing the mass concentration of Ca2+ or increasing the mass concentration of SO42- can prompt the ion-exchange reaction on the rock surface and detachment of polar components from the surface. Consequently, the wettability of the rock surface strengthens, augmenting the recovery process. Nuclear magnetic resonance experiments evidence that low-salinity water injection, with ion adjustment, significantly alters the interactions between the rock and fluid in tight sandstone reservoirs. As a result, the T2 signal amplitude decreases significantly, residual oil saturation reduces considerably, and the hydrophilic nature of the rock surface increases.

A Feasibility Study on Enhanced Oil Recovery of Modified Janus Nano Calcium Carbonate-Assisted Alkyl Polyglycoside to Form Nanofluids in Emulsification Flooding.

Emulsification flooding can effectively enhance crude oil recovery to solve the problem of petroleum shortage. In this work, a modified Janus Nano Calcium carbonate (JNC-12) with a particle size of 30-150 nm was synthesized, and an in situ emulsification nanofluid (ISEN) was prepared with JNC-12 and alkyl polyglycoside (APG). Scanning electron microscope (SEM) showed that the dispersion of JNC-12 in air or APG solution was better than Nano Calcium carbonate (Nano CaCO3). The emulsification properties, interfacial tension, and expansion modulus of ISEN were studied, and the result showed that with the increase in salinity, the emulsification rate decreased, the water yield rate increased, the interfacial tension first decreased and then increased, and the expansion modulus first increased and then decreased. With the increase in temperature, the emulsification rate, emulsion viscosity, and interfacial tension decreased. With the increased oil-water volume, the water yield rate and the emulsion viscosity increased. With increase in the concentration of JNC-12, the water yield rate, the emulsion viscosity, and the interfacial tension decreased but the expansion modulus increased. The emulsion generated by emulsifying ISEN with crude oil was an O/W emulsion, the crude oil viscosity was 4-10 times that of emulsion, and the average particle size of emulsion was 1.107 μm. The addition of ISEN caused the decrease in interfacial tension of oil-water to 0.01-0.1 mN/m. The wettability alteration experiment found that ISEN could change the lipophilic rock to hydrophilic rock. Finally, the core displacement experiments showed that compared with the first water flooding, the oil recovery of the second water flooding after ISEN flooding enhanced by 17.6%. This research has important guiding significance for in situ emulsified nanofluid flooding to enhance oil recovery.

Migration characteristics and plugging rules of self-aggregating nanoparticles in the porous media

Nanoparticle profile control agents have been widely used for water shut-off treatment due to their excellent properties. However, the contradiction between the injectability and the plugging characteristics of profile control agents seriously affects their sealing effect. Self-aggregating nanoparticles can effectively alleviate this contradiction by forming particle clusters in the formation to block water channels. In this study, the injection and plugging properties of self-aggregating nanoparticle profile control agents in porous media were investigated using visual porous media etching model and core model. Injectivity experiments showed that the flow of nanoparticles in porous media was divided into three phases: flow dispersion phase, self-aggregation migration phase, and aggregation plugging state. They could aggregate to form clusters similar to the pore throat size after 60 min. Core displacement experiments showed that the plugging performance of nanoparticles was influenced by solution concentration, injection volume, injection rate, and core permeability. When injecting a 3000 mg/L nanoparticle solution into the core at 60 °C, the residual resistance coefficient was larger than 1.83. The retention rate in pore throats was superior to 60%.

Research on the Water Injection Pressure Reducing and Increasing Injection System for Low Permeability Reservoirs in Fushan Oilfield

In response to the problems of increased injection pressure, decreased injection volume, and stopped injection caused by scaling and impurity blockage during the water injection process in the low permeability reservoir of HuaX block in Fushan Oilfield, water quality analysis and scaling experiments were conducted on the injected water in the block to determine the cause of scaling. Secondly, core displacement damage experiments were conducted using natural rock cores and on-site injected water to determine the degree of permeability damage during the water injection process, with a permeability damage rate greater than 70%, Finally, based on the causes of scaling and core displacement experiments, scale inhibitors, anti expansion agents, and surfactants were selected. Through orthogonal experiments, the optimal system formula was determined. The scale inhibition rate was greater than 90%, the anti expansion agent was greater than 90%, and the interfacial tension was less than 0.01mN/m. Core displacement experiments showed that the permeability damage rate of the system to the core was less than 15%, which can achieve the effect of reducing pressure and increasing injection in water injection wells.

Preparation of polymer microspheres as oil displacement agent for extra-high temperature and extra-high salinity reservoirs

Based on the difficult problem that conventional polymer and gel can't be used for enhancing oil recovery in extra-high temperature (200 °C) and extra-high salinity (2 ×105 mg/L) reservoirs，an anti-temperature anti-salinity microspheres was prepared with 2,2′-bis[4-(4-aminophenoxy)phenyl] propane (BAPP), 3, 3′, 4, 4′-diphenyl ether dianhydride (ODPA) and phthalic anhydride (PA) as the monomers. The FTIR results showed that the temperature- and salt-resistant polyimide (PI) microspheres were prepared as target product. TGA showed that thermal decomposition of the unaged and aged PI-2 microspheres occurred over 281 °C and 252 °C, respectively; These values greatly exceed those of commercial HPAM, weak gel particles and pre-crosslinked gel particles. After the polyimide microspheres were aged for 120 d, the enhanced oil recovery of the PI-2 microspheres does not decrease significantly, so the long-term stability of two polyimide microspheres are very good at 200 °C and total dissolved solids (TDS) = 2 × 105 mg/L. The PI-2 microspheres had better properties than the conventional polymer and gel as profile control agent and water plugging agent. The microspheres possess the characteristics of being able to inject, block, and move, resulting in excellent oil displacement efficiency. The results of core displacement experiments revealed that PI-2 microspheres are highly efficient in oil displacement and have a strong ability to improve the water injection profile. Therefore, PI-2 microspheres can be used as an oil displacement agent in reservoirs with extremely high temperature and salt content.

Anti-temperature anti-salinity nanospheres: Preparation, characterization, thermal stability, plugging ability and oil displacement

Based on the difficult problem that conventional polymer and gel can't be used for enhancing oil recovery in extra-high temperature (200 °C) and extra-high salinity (2 × 105 mg/L) reservoirs，an anti-temperature anti-salinity nanospheres was prepared with APB, ODPA and PA as the monomers. The results of FTIR showed the final products were target nanospheres. TG showed that thermal decomposition of the polyimide (PI-1) nanospheres occurred at 440 °C; these values greatly exceeded those of commercial HPAM, weak gel particles and pre-crosslinked gel particles. After the polyimide nanospheres were aged for 120 d, the enhanced oil recovery of the PI-1 nanospheres does not decrease significantly, so the long-term stability of two polyimide nanospheres are very good at 200 °C and TDS = 2 × 105 mg/L. The PI-1 nanospheres had better properties than the conventional polymer and gel as profile control agent and water plugging agent. The nanospheres have the characteristics of “able to inject, able to block, able to move”, and the oil displacement efficiency is very excellent. The results of core displacement experiments revealed that PI-1 microspheres had high oil displacement efficiency and strong ability to improve water injection profile. Therefore, the PI-1 microspheres can be used as oil displacement agent in extra-high temperature and extra-high salt reservoirs.

Preparation of carbon-based active nanofluids with temperature and salt resistance for enhanced oil recovery

The abundant hydrophilic surface groups endow carbon-based nanoparticles (CDs) with intrinsic great dispersibility, however, the strong hydrophilicity limits the oil–water interface activity, restraining the performance in enhanced oil recovery. Developing CDs with simultaneously ultra-small sizes, high temperature and salt tolerance, as well as superior interfacial activity is of great significance. In this work, CDs with the size of 3.3 nm and excellent temperature and salt resistance were prepared by hydrothermal reaction, using citric acid (CA) and ethylenediamine (EDA) as precursors. Carboxyl ether carboxylate-6Na (APEC-6Na) was selected as the compound agent to construct carbon-based active nanofluids (CANs) with excellent oil–water and oil-solid interfacial activities. CANs can reduce the oil–water interfacial tension to 8.9 × 10-4 mN m−1, withstand a temperature up to 90°C and a salinity up to 6.3 × 104 mg·L-1. Even at the highest tolerant salinity, the underwater oil contact angle of 155° can be achieved, demonstrating excellent wettability control capability, which could be attributed to the synergistic effect of the compound CANs system. The increase of the contact angle of underwater oil droplets facilitates the coalescence of oil film on the lipophilic surface to form oil droplets. The electrostatic repulsion generated by the adsorption of CDs and APEC-6Na at the oil–water interface and rock surface makes the coalesced oil droplets more easily detached from the rock surface, and the oil film reduction rate exceeds 97.7 % within 24 h. The excellent oil–water and oil-solid interface properties and the structural separation pressure endows CANs with remarkable performance in core displacement experiments. Compared with simulated formation water, CANs can improve the recovery rate by 26.3 %, exhibiting important application value for improving the recovery rate of ultra-low permeability reservoirs.

Effect of hydroxy group activity on the hydrogel formation temperature of β-cyclodextrins and its application in profile control

In order to increase the gelling temperature of β-CD-based hydrogels and expand the application range of β-CD-based hydrogels in oil reservoirs, glycidyl ethers with different chain lengths were prepared for modification of β-CDs, and then the modified β-CD was chemically crosslinked with epichlorohydrin (EPI) to prepare hydrogels. Thus, the gelling temperature of β-CD hydrogels was successfully increased from 65 to 125 °C. FTIR, 1H NMR, XRD and DSC were used to investigate the mechanism of the changing of gelling temperature. The results showed that the long chain alkyl changed the electron cloud density on the β-CD ring, increased the difficulty of hydroxyl group leaving, thus increased the gel forming temperature. Furthermore, the swelling behavior and the core plugging performance of the gel were evaluated. The results indicated that the maximum swelling rate of modified β-CD gel was 75 %. The core displacement experiment showed that the plugging rate was greater than 95 %, the unplugging rate was greater than 90 %, and the maximum breakthrough pressure of water flooding reached 7.43 MPa. These results indicated the practical value of β-CD hydrogels in high temperature (60–125 °C) oil fields.

Laboratory Evaluation of a Low-Damage Authigenic Mud Acid System for Bai-823 Well Block.

Aiming at the problem of single and poor adaptability of Bai-823 plugging removal system, an authigenic mud acid system using methyl formate, ammonium chloride, and ammonium fluoride as raw materials is proposed, which can adapt to the temperature of 60-80 °C of the target reservoir and sandstone lithology. The acid-generating capacity of the authigenic acid system at different temperatures was evaluated. The results showed that the H+ concentration remained at 3.35 mol/L after 180 min at 80 °C, which indicated that authigenic acid could generate acid continuously and thus be competent for acidizing and plugging removal of further wells. The corrosion rate of authigenic acid to N80 steel was further investigated. When 2 wt % SA1-3B corrosion inhibitor was used, the corrosion rate was only 0.15 g/(m2·h). At the same time, the corrosion capacities of authigenic acid to rock core and scale samples were studied, which were 19.38 and 93.81%, respectively, indicating that the authigenic acid system realized pipeline and reservoir friendliness when it was able to effectively remove plugging. Finally, a core displacement experiment was carried out to simulate reservoir acidizing for plugging removal. The results showed that the core permeability increased from 1.00 to 1.63 after acidizing modification with authigenic acid. All of the above studies show that a kind of authigenic mud acid has been successfully prepared, and a new idea for the authigenic acid system has been proposed.

Research Progress on CO2 Capture, Utilization, and Storage (CCUS) Based on Micro-Nano Fluidics Technology

The research and application of CO2 storage and enhanced oil recovery (EOR) have gradually emerged in China. However, the vast unconventional oil and gas resources are stored in reservoir pores ranging from several nanometers to several hundred micrometers in size. Additionally, CO2 geological sequestration involves the migration of fluids in tight caprock and target layers, which directly alters the transport and phase behavior of reservoir fluids at different scales. Micro- and nanoscale fluidics technology, with their advantages of in situ visualization, high temperature and pressure resistance, and rapid response, have become a new technical approach to investigate gas–liquid interactions in confined domains and an effective supplement to traditional core displacement experiments. The research progress of micro–nano fluidics visualization technology in various aspects, such as CO2 capture, utilization, and storage, is summarized in this paper, and the future development trends and research directions of micro–nano fluidics technology in the field of carbon capture, utilization, and storage (CCUS) are predicted.

Evaluation of the Effects of Nano-SiO2 Microemulsion on Decompression and Augmented Injection in the Eunan Tight Reservoir

The residual oil saturation of the matrix near the well zone of a tight reservoir is high due to the tight reservoir’s complex conditions, such as the small pore throat radius and low permeability of the matrix and the development of microfractures, which can result in serious water channeling, even after long-term water injection development. The aim of this paper is to improve the effects of depressurization and augmented injection for tight reservoir waterflooding development by reducing the tight matrix’s residual oil saturation, increasing and maintaining its water phase permeability near the well zone using a nano-SiO2 microemulsion system with a small particle size and high interfacial activity. Therefore, four nano-microemulsion systems were evaluated and screened for their temperature resistance, salt resistance, interfacial tension, solubilization, and dilution resistance. A microemulsion system of 13% A + 4% B + 4% C + 4% n-butanol + 6% oil phase + 69% NaCl solution (10%) + 1% OP-5 + 0.5% anti-temperature agent + 0.3% nanosilica material was preferred. According to the core displacement experiment, the depressurization rate can reach 28~60% when the injection concentration of the system is 1~10% and the injection volume is 2~5 PV. The results of the on-site test show that the water injection pressure dropped to 17.5 MPa, which was lower than the reservoir fracture re-opening pressure. The pressure reduction rate was approximately 20%. The validity period of the depressurization and augmented injection has reached 23 months to date.

Development and Characterization of CO2-Responsive Intelligent Polymer Sealant.

In this study, we present an innovative intelligent polymer sealant designed to mitigate CO2 leakage during underground geological storage (CCUS). This sealant is formulated by cross-linking CO2-responsive polymers, specifically acrylamide (AM) and N-[3-(dimethylamino) propyl] methacrylamide (DMAPMA), with polyethylenimine (PEI) serving as the cross-linking agent. The polymer sealant's characteristics were systematically investigated, varying the CO2-responsive polymer content (1.5 wt %) and PEI content (0.1-0.6 wt %). A comprehensive analysis encompassing the rheological properties, thermal behavior, conductivity, and microstructures was conducted. Experimental results indicate that the polymer sealant exhibits excellent injectability, rapid response kinetics, thermal stability, and robust mechanical strength. Upon encountering CO2, the polymer system undergoes a transition from sol to gel state, forming a surface-smooth, uniformly porous three-dimensional (3D) network skeleton structure. Remarkably, the gel's modulus remains relatively unaffected by the shear frequency. Core fluid displacement experiments demonstrated a substantial sealing efficiency of 73.6% for CO2 and an impressive subsequent injection water sealing rate of 96.2%, underscoring its superior sealing and migration performance. In conclusion, the proposed CO2-responsive gel sealant exhibits an exceptional potential for successful utilization in CCUS operations. This advancement introduces a novel avenue to enhance the effectiveness of CO2-responsive gel sealants, thereby contributing to the advancement of CO2 leakage mitigation strategies in geological storage scenarios.

An amphiphilic nano calcium carbonate: Preparation, emulsification, interface properties, and displacement mechanism in low permeability reservoir

More extensive attention has been directed toward amphiphilic nanomaterials in the field of chemical enhanced oil recovery owing to they have the same excellent properties as surfactants. In this work, an amphiphilic nano calcium carbonate(ANCC) was prepared by chemical one-pot synthesis of NCC and alkyl acid. ANCC had a lipophilic property, which can make the oil and water were completely emulsified at the concentration of 500 ppm to form W/O emulsion with a particle size of 0.2–2.6 µm. ANCC had best dispersion effect at the solution of 0.1% Tween80. In the oil-water phase, ANCC can be adsorbed on the oil-water interface to reduce interface tension, and increase interface strength, and improve emulsion stability. The lipophilic slide can be changed from lipophilic to hydrophilic when immersed in the nanofluid. Using TW-ANCC (0.1% of Tween80 +500 ppm of ANCC) as the oil displacement fluid, which improved oil recovery by 23.3% in the single core displacement experiment and by 36.9% in the flat panel visualization experiment with comparing primary water flooding. The oil displacement mechanism of TW-ANCC was obtained by the etched glass micromodel experiment and the nuclear magnetic resonance experiment, the result shown that TW-ANCC can enhance oil recovery by reducing interface tension, changing rock wettability, reducing flow in high permeability zone, and expanding sweep volume in low permeability zones.

Effects of CH4/CO2 multi-component gas on components and properties of tight oil during CO2 utilization and storage: Physical experiment and composition numerical simulation

An essential technology of carbon capture, utilization and storage-enhanced oil recovery (CCUS-EOR) for tight oil reservoirs is CO2 huff-puff followed by associated produced gas reinjection. In this paper, the effects of multi-component gas on the properties and components of tight oil are studied. First, the core displacement experiments using the CH4/CO2 multi-component gas are conducted to determine the oil displacement efficiency under different CO2 and CH4 ratios. Then, a viscometer and a liquid density balance are used to investigate the change characteristics of oil viscosity and density after multi-component gas displacement with different CO2 and CH4 ratios. In addition, a laboratory scale numerical model is established to validate the experimental results. Finally, a composition model of multi-stage fractured horizontal well in tight oil reservoir considering nano-confinement effects is established to investigate the effects of multi-component gas on the components of produced dead oil and formation crude oil. The experimental results show that the oil displacement efficiency of multi-component gas displacement is greater than that of single-component gas displacement. The CH4 decreases the viscosity and density of light oil, while CO2 decreases the viscosity but increases the density. And the numerical simulation results show that CO2 extracts more heavy components from the liquid phase into the vapor phase, while CH4 extracts more light components from the liquid phase into the vapor phase during cyclic gas injection. The multi-component gas can extract both the light components and the heavy components from oil, and the balanced production of each component can be achieved by using multi-component gas huff-puff.