Core Displacement Experiments Research Articles

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.

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.

A Simulation of Core Displacement Experiments for the Determination of the Relative Permeability

Computations of the relative permeability curves were made through their representation by two functions for wetting and nonwetting phases. Each function contains one parameter that controls the shape of the relative permeability curves. The values of these parameters are chosen to minimize an objective function, that is represented as a weighted sum of the squared differences between experimentally measured data and the corresponding data calculated by a mathematical model simulating the experiment. These data comprise the pressure drop across core samples and the recovery response of the displacing phase. Two mathematical models are constructed in this study to simulate incompressible, one-dimensional, two-phase flow. The first model describes the imbibition process and the other describes the drainage process. The values of the relative permeability parameters are calculated by employing Rosenbrock optimization procedure. The reliability of this procedure has been confirmed by applying it to four displacement cases. The optimum values of the relative permeability parameters, which reflect the final shape of the relative permeability curves, are achieved at the minimum value of the objective function. All the above processes are be embodied in relative permeability package RPP which is constructed in this study using FORTRAN language.

Study on migration and plugging performance of polymer gel in fractured cores using nuclear magnetic resonance technology

In situ cross-linked polymer gels (ISCPGs) are widely used for conformance control and enhanced oil recovery (EOR) in heterogeneous petroleum reservoirs. However, the mechanisms behind their migration and plugging in fractured cores remain unclear. In this study, changes in the injection pressure difference before and after the treatment of HPAM/phenolic resin gel was monitored by core displacement experiment. The gel was injected with two different gelation states, i.e., gelant and pre-crosslinked gel. Meanwhile, we analyzed the nuclear magnetic resonance (NMR) T2 signal and imaging of the cores that were treated with the polymer gel system during various injection stages. Results indicated that NMR technology can effectively analyze the migration and plugging performance of polymer gels in fractured cores at a microscopic level, both before and after gelation. The gelant effectively plugged the fracture when the injection rate was low, but a great amount of the gelant entered the matrix and damaged the matrix. In contrast, it formed a plugging layer at the inlet face and also caused damage at high injection rates. For conformance treatment of pre-crosslinked gels, the gel did not easily enter the matrix. When the injection rate of pre-crosslinked gels increased, its plugging efficiency for the fractured cores enhanced. Therefore, engineers should optimize gel state, injection rate, and injection pressure according to the specific reservoir conditions before oilfield operations. This study can help researchers understand the microscopic migration and plugging mechanism of polymer gels in cores at the microscopic level. It will also help researchers to pay more attention to the NMR technique to further understand its application in petroleum reservoir conformance improvement.

Synthesis and Enhanced Oil Recovery Potential of the Bio-Nano-Oil Displacement System.

Nanoparticles (NPs) have attracted great attention in the tertiary oil recovery process due to their unique properties. As an economical and efficient green synthesis method, biosynthesized nanoparticles have the advantages of low toxicity, fast preparation, and high yield. In this study, with the theme of biotechnology, for the first time, the bio-nanoparticles reduced by iron-reducing bacteria were compounded with the biosurfactant produced by Bacillus to form a stable bio-nano flooding system, revealing the oil flooding mechanism and enhanced oil recovery (EOR) potential of the bio-nano flooding system. The interfacial properties of the bio-nano-oil displacement system were studied by interfacial tension and wettability change experiments. The enhanced oil recovery potential of the bio-nano-oil displacement agent was measured by microscopic oil displacement experiments and core flooding experiments. The bio-nano-oil displacement system with different nanoparticle concentrations can form a stable dispersion system. The oil-water interfacial tension and contact angle decreased with the increase in concentration of the bio-nano flooding system, which also has a high salt tolerance. Microscopic oil displacement experiments proved the efficient oil displacement of the bio-nano-oil displacement system and revealed its main oil displacement mechanism. The effects of concentration and temperature on the recovery of the nano-biological flooding system were investigated by core displacement experiments. The results showed that the recovery rate increased from 4.53 to 15.26% with the increase of the concentration of the system. The optimum experimental temperature was 60 °C, and the maximum recovery rate was 15.63%.

Experimental Evaluation of Combined Plugging System for CO2-Improved Oil Recovery and Storage

High-performance CO2-improved oil recovery (IOR) and storage technology is one of the most promising measures for global oilfield companies to achieve zero carbon targets. Due to the severe heterogeneity of most petroleum reservoirs and the significant density difference between CO2 and reservoir fluid, the efficiency of CO2-IOR and storage is usually limited. In this paper, a high-temperature and high-pressure 30 cm core displacement experiment was used to study the CO2 conformance control performance of both the single- and the combined plugging system in long sandstone cores. The single systems evaluated included polymer gels, CO2 foams, and CO2-responsive thickening polymer (CO2-RTP) systems. The combined systems were pairwise combinations of the three of them. Results show that the pressure rise and maximum breakthrough pressure of the gel system were the highest among three single-plugging systems. Its plugging efficiency was the highest, reaching 86.13%. At the same time, its gas production reduction rate was also the highest, reaching 95.71%. In the parallel 30 cm core plugging experiments, three combined plugging systems all showed excellent plugging and CO2 conformance improvement performance. Among them, the combined plugging systems containing polymer gels had larger plugging efficiency, and their gas production reduction ratios reached about 90%. Compared with single systems, the combined plugging systems had the advantages of easy injection and in-depth propagation, which can significantly improve CO2 conformance and oil recovery. The research results of this study can provide the experimental understanding and theoretical guidance for the current tricky oilfield problems of CO2 channeling.

The evaluation of dodecyl hydroxy sulfobetaine as a high-temperature and high-salinity resistant foaming agent in sandstone reservoirs

For the high temperature (130 °C), high pressure (30 MPa), and high salinity (2.5 × 105 mg/L) of formation water conditions in the target block of the Tarim Basin Oilfield in northwest China, dodecyl hydroxy sulfobetaine surfactant was evaluated for its foaming performance, thermal stability, adsorption performance. The evaluation results showed that the surfactant exhibited good foaming ability and thermal stability than the general carboxy betaine under the above harsh conditions. The static adsorption of the surfactant on the surface of quartz sand particles was less than 1 mg/g with a concentration of less than 0.4%, which met the requirement for foaming agent adsorption. Moreover, the results of core displacement experiments indicated that, when simultaneously injecting 0.4% foaming agent and gas at a volume ratio of 3:7 into the cores of 38 mD, 161.4 mD, and 478.7 mD, foam with low mobility of less than 2 mD/cP could be generated; in the 57.3 mD Berea core, the resistance factor of foam generated by 8 cycles of injecting gas-liquid alternately with gas-liquid volume ratio ranging from 0.2:0.1 to 0.4:0.1 was nearly 20, and the residual resistance factor was greater than 5 after 5 PV of continuous gas injection. The results of the study can guide the selection of foaming agents for gas mobility control in high-temperature and high-salinity sandstone reservoirs.

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

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

Experimental Study on Switchable Acetamidine Surfactant Flooding in Sandstone Using NMR

As a promising chemical-enhanced oil recovery method (CEOR), switchable acetamidine surfactant flooding is investigated in sandstone oil reservoirs. To describe the distributions of the injected water during the surfactant flooding, long-time and multifrequency NMR scanning was employed in combination with core displacement experiments. We found that the water saturation increased and swept volume was improved with the injection rates increasing from 0.01 to 0.5 mL/min in all pores. During water flooding, the water injection rate and distribution had a positive correlation. The water saturation increased as the surfactant concentration increased, and the water saturation and the swept volume of surfactant flooding were larger than those of the water flooding. Furthermore, the water saturation increase in migration pore (MP) was much larger than that in other pores during the switchable acetamidine surfactant flooding. As a result, the water saturation increased and the oil recovery enhanced. Our research results provided novel perspectives on switchable acetamidine surfactant flooding for enhanced oil recovery (EOR).

The numerical simulation study on the dynamic variation of residual oil with water drive velocity in water flooding reservoir

The results of core displacement experiments show that increasing the water drive velocity when it is bigger than the limit value can effectively reduce the residual oil saturation and improve the oil displacement efficiency under the same PV. However, the existing commercial simulators (Eclipse, CMG et al.) cannot simulate the effect of water velocity on the relative permeability curve in the process of numerical simulation.In this article, capillary number (Ca), defined as the dimensionless ratio of viscous force to capillary force, is used to characterize the relationship between water drive velocity and residual oil. Second, a new Boltzmann (BG) equation is proposed to match the nonlinear relationship between Ca and residual oil. The BG equation is a continuous function, which is very beneficial to the stability of numerical calculation. Finally, a new reservoir numerical simulator is established which captures the dynamic variation of residual oil saturation with water drive velocity in a water flooding reservoir based on the black oil model. The new simulator was verified by comparing it with the commercial reservoir simulator ECLIPSE and experimental data. The simulation results show that compared with the common model, the model considering the dynamic variation of residual oil saturation with water drive velocity reduced the residual oil saturation near the main flow line after enhanced injection rate. The oil phase flow capacity in the model is enhanced, the water cut is decreased, and the oil recovery rate is higher. The history matching of the S oilfield in Bohai Bay is achieved with the new simulator, and the history matching accuracy is obviously higher than that of Eclipse. The findings of this study can help with a better understanding of the distribution law and flow law of remaining oil in the high water cut stage of the reservoir and have good theory and application value for water flooding offshore oilfields.

EVALUATION OF SUPERCRITICAL CO2 FRACTURING EFFECT IN DA'AN RESERVOIR OF SONGLIAO BASIN

Carbon dioxide (CO&lt;sub&gt;2&lt;/sub&gt;) fracturing technology is introduced to improve the development effect of low permeability reservoirs. To understand the advantages of CO&lt;sub&gt;2&lt;/sub&gt; fracturing and the mechanism of CO&lt;sub&gt;2&lt;/sub&gt; assisting oil displacement efficiency, laboratory core displacement experiments and nuclear magnetic resonance (NMR) tests are conducted. For core displacement experiments, a water flooding, a water flooding-CO&lt;sub&gt;2&lt;/sub&gt; huff and puff experiment are conducted. Water flooding simulates the oil displacement after hydraulic fracturing and the latter simulates the effect after CO&lt;sub&gt;2&lt;/sub&gt; fracturing. Furthermore, an NMR test is conducted in each stage of the experiments to quantify the recovery degree of crude oil in different pore throats for a low-permeability reservoir. The results show that the water flooding recovery of the two cores is 31.26&amp;#37; and 30.14&amp;#37;, respectively. The CO&lt;sub&gt;2&lt;/sub&gt; huff and puff enhanced oil recovery and subsequent water flooding are 11.48&amp;#37; and 5.19&amp;#37;, respectively. Compared with conventional hydraulic fracturing, CO&lt;sub&gt;2&lt;/sub&gt; fracturing enhanced oil recovery by 15.55&amp;#37;. Furthermore, the crude oil recovery degree of water flooding in macro-pores is 75.71&amp;#37;, while that in mesopores is 62.17&amp;#37; and that in small pores is 7.49&amp;#37;. After CO&lt;sub&gt;2&lt;/sub&gt; huff and puff, the recovery degrees in macropores, mesopores, and small pores are 99.10&amp;#37;, 67.51&amp;#37;, and 23.21&amp;#37;, respectively. It demonstrates CO&lt;sub&gt;2&lt;/sub&gt; can penetrate deeply into the tiny pores that cannot be affected by water flooding for oil displacement, effectively increasing the swept volume and improving the oil recovery. Research shows the advantages of CO&lt;sub&gt;2&lt;/sub&gt; fracturing and may help to enlarge its application in low-permeability reservoirs.

Experimental investigation of divalent ions and screening in smart water on calcite rock surface

Massive demand for fossil fuel against limited available oil conventional reservoirs worldwide highlights that innovative enhanced oil recovery method. Nowadays, due to the accessibility of seawater and rivers, smart water and low salinity water injection have gained more attention. This paper addresses the mechanisms behind smart water injection and studies a real case from a carbonate oil reservoir. For this purpose, contact angle measurement was employed to screen and find the best smart water composition among different types of water. A core flooding experiment was used to evaluate the performance of the smart water injection in calcite rock. Two different scenarios were implemented in the core displacement experiment to examine the effect of divalent ions. Based on the experimental results, the main mechanism behind the smart water injection is the wettability alteration of the calcite rock surface. Also, as the most central divalent ions, an increase in calcium ions has been effective in increasing the water wetness of the rock surface, resulting in river water with double calcium ion content as the best smart water. [Received: November 8, 2021; Accepted: June 2, 2022]