The gel with dually crosslinked polymer network (DPN) based on supramolecular interaction and chemical crosslinking usually has excellent temperature and shear resistance. The gel fracturing fluid with DPN will provide a new working fluid strategy for the efficient development of deep/ultra-deep oil and gas. Herein, a delayed crosslinking gel fracturing fluid with DPN is reported, which is formed by a supramolecular enhanced polymer containing catechol groups and a multisite organic zirconium delayed crosslinker. The gel breaker and cleanup additive are optimized, and the gel breaking liquid is uniform and had high surface/interface activity. The gel fracturing fluid has excellent delayed crosslinking ability, temperature resistance and shear resistance. It can be crosslinked to the hanging state within 233 s, and the residual viscosity is 71 mPa & sdot;s after shearing at 200 degrees C. The delayed crosslinking behavior and mechanism of gel fracturing fluid are further analyzed by viscoelastic rheological experiment and gelation kinetics calculation. Before reaching the temperature threshold of chemical crosslinking (70 degrees C), the system is dominated by supramolecular polymer network (SPN). After reaching 70 degrees C, the addition of chemical crosslinking makes SPN become DPN. The Avrami kinetic calculation results show that the gel growth mode at 70 degrees C changes from multi-dimensional diffusion growth to one-dimensional linear rapid growth. In addition, the final one-dimensional linear rapid growth stage of gelation is not controlled by temperature. The temperature mainly affected the multidimensional growth stage of gelation.

Before developing energy minerals, core physical simulation experiments are essential to evaluate the effectiveness of development methods. This study proposes a nondestructive method for preparing multivoid structure cores using a thermosensitive phase-change material. Natural camphor powder, evenly mixed with quartz sand, volatilized to form secondary pores, with key volatilization factors determined experimentally. The effects of various parameters on core matrix porosity and permeability were systematically analyzed, and predictive equations were established using statistical methods. Additionally, camphor blocks of specific shapes and sizes, compressed under high pressure, volatilized within the cores to create fractures and caves. Nuclear magnetic resonance imaging (NMRI) reconstruction and three-dimensional core modeling confirmed that this method allowed precise control over the location and size of fractures/caves while maintaining core integrity. This work provides a cost-effective approach to fabricating artificial multivoid structure cores with controllable parameters, offering a valuable foundation for future oilfield development research.

Novel wet-phase modified expandable graphite (WMEG) particles were developed for in-depth profile control in carbonate reservoirs. The harsh environment of carbonate reservoirs (≥ 130 °C, ≥ 22 × 104 mg/L) brings significant challenges for existing profile control agents. WMEG particles were developed to address this problem. WMEG particles were synthesized via intercalation with ultrasound irradiation and chemical oxidation. The critical expansion temperature of WMEG particles is 130 °C, and these particles can effectively expand 3–8 times under high temperature and high salinity water. The core flow experiments show that WMEG particles exhibit a good plugging capacity, profile control capacity, and a better-enhanced oil recovery (EOR) capacity in deep carbonate reservoirs. WMEG particles can be expanded in the formation and form larger particles that bridge the upper and lower end faces of the fracture. Then the high-permeability zones are effectively plugged, and the heterogeneity is improved, resulting in an obvious increase in oil recovery. This research provides a novel insight into future applications of profile control agents for in-depth profile control treatment in carbonate reservoirs.

High-temperature steam injection is a primary method for viscosity reduction and recovery in heavy oil reservoirs. However, due to the high mobility of steam, channeling often occurs within the reservoir, leading to reduced thermal efficiency and challenges in enhancing oil production. Foam fluids, with their dual advantages of selective plugging and efficient oil displacement, are widely used in steam-injection heavy oil recovery. Nonetheless, conventional foams tend to destabilize under high-temperature conditions, resulting in poor stability and suboptimal plugging performance, which hampers the efficient development of heavy oil resources. To address these technical challenges, this study introduces a foam system reinforced with Janus nano-graphite, a high-temperature stabilizer characterized by its small particle size and thermal resistance. The foaming agents used in the system are sodium α-olefin sulfonate (AOS), an anionic surfactant, and octadecyl hydroxylpropyl sulfobetaine (OHSB), a zwitterionic surfactant. Under conditions of 250 °C and 5 MPa, the foam system achieved a half-life of 47.8 min, 3.4 times longer than conventional foams. Janus nano-graphite forms a multidimensional network structure in the liquid phase, increasing internal friction and enhancing shear viscosity by 1.2 to 1.8 times that of conventional foams. Furthermore, the foam gel system demonstrated effective steam-channeling control in heterogeneous heavy oil reservoirs, particularly in reservoirs with permeability differentials ranging from 3 to 9. These findings suggest that the Janus nano-graphite reinforced foam system holds significant potential for steam-channeling mitigation in heavy oil reservoirs.

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.

In the process of the large-scale hydraulic fracturing development in oil and gas fields, reservoir damage caused by polymer fracturing fluid is inevitable. The real oil and gas field reservoir conditions make the causes of reservoir damage more complicated, and few reports have provided an in-depth analysis of the composition and structure of actual blockages generated in production wells after hydraulic fracturing. In this work, we innovatively obtained reservoir blockages from production wells after fracturing in oil and gas fields, analyzed their physical and chemical properties by SEM, XRD, IR and other methods, then reproduced the blockages formation process in the laboratory through ampoule aging experiments, and evaluated their impact on the reservoir damage rate and fracture flow capacity by core flow physical simulation experiments. The results indicate that the blockages primarily consist of polyacrylamide and iron ions complexes. For the formation process of blockages, the gel breaker solution will release iron ions after reacting with iron calcite existed in the reservoir. The carboxyl group of polyacrylamides and Fe3+ ions can further form highly stable -(COO)3Fe bonds. The physical simulation results revealed that the generation of Fe3+ ions significantly enhanced the extent of reservoir damage and reduction rate of fracture conductivity associated with polyacrylamide fracturing fluid. In addition, after complete gel breaking, the weak interactions between the short-chain molecular groups and Fe3+ ions result in limited molecular flocculation and entanglement, leading to the reduction in reservoir damage. By identifying the specific formation causes of blockages, we revealed the reservoir damage mechanism from a novel perspective, which is of great significance for guiding the development of low damage fracturing fluid system and further improving oil and gas recovery.

With high clay content in shale gas reservoir, the hydration is easy during hydraulic fracturing, which will affect the fracture conductivity and productivity of gas wells. The illite content of the Longmaxi formation shale in Yongchuan District is high (more than 80% of clay mineral content), and gas wells have a high productivity after fracturing and shut-in. However, the hydration effect mechanism of fracturing fluid on illite rich shale is not clear. Therefore, in this paper, core hydration experiments are performed for the illite rich shale reservoir. The water imbibition characteristic of near-fracture shale is obtained, and the micro-morphology and microfracture development characteristics of hydration are studied. Moreover, the hydration mechanism of near-fracture shale is then explored from the aspects of ion diffusion and mineral interlayer spacing variation. It is deduced that the fracturing fluid is spontaneously imbibed into small pores preferentially during well shut-in after fracturing. After the near-fracture shale is touched by water, some clay minerals peel and fall off from the fracture surface after hydration, accompanied by the development of microfractures. The interlayer spacing of clay minerals expands (smectite expands by 8.8% and illite 1.5%) after water immersion, and the ion diffusion occurs. The first 15 h is the rapid diffusion stage (surface effect), while the second 15 h is the stable rising stage (internal effect). This study systematically analyzes the hydration characteristics of near-fracture illite rich shale and reveals its hydration mechanism, which are crucial for the optimization of well shut-in time and exploitation system of shale gas reservoir after fracturing.

The membrane method based on adaptive wettability shows great advantages in oil-water separation. At present, researches focus on the excellent application performance of the membrane material, while the quantitative analysis of interactions in oil-water separation is rarely recognized. Herein, we constructed an adaptable wettability membrane with multiple polymer networks by polydopamine (PDA) and mussel-inspired amphiphilic polymer. Based on the Owens three-probe liquid method, the surface energy of the modified membrane was verified to meet the adaptive wettability conditions, with surface energies (gS) of 147.6 mJ m-2 (superhydrophilic/underwater superoleophobic) and 49.87 mJ m-2 (superhydrophobic/superoleophobic), respectively. The adhesion or repulsion of the membrane to the oil phase under different conditions during the separation process was quantified by the chemical probe AFM technique. In addition, the oil-water selective separation mechanism was further analyzed in a simplified membrane microchannel model. The results show that the different wetting produces capillary additional pressure in opposite directions, resulting in different energies to be overcome when the oil or water passes through the microchannels, thus achieving selective separation. (c) 2023 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/ 4.0/).

With the increasing demand for oil and gas resources, deep tight oil and gas reservoirs have gradually become the focus of global oil and gas exploration and development. Hydraulic fracturing technology based on water-base fracturing fluid plays a more and more important role in improving the recovery of tight oil reservoirs. Under the background of global CO2 emission reduction, a CO2-responsive clean fracturing fluid with controllable gelling/gel breaking at high temperatures was constructed in this paper. The system was not only friendly to the reservoir and environment, but also overcame the shortcomings of the traditional clean fracturing fluid with undesirable temperature resistance. The viscosity characteristics and viscoelastic behavior of temperature-resistant clean fracturing fluid were investigated through high-temperature rheology experiments. The interaction between fluid and rock was investigated through the core flow experiment. The results showed that the clean fracturing fluid had the characteristics of good CO2 responsiveness, excellent shear resistance at high temperatures, high drag reduction, satisfactory gel breaking performance, low filtration and low core damage. The complex three-dimensional network structure formed by the intertwined micelles and vesicles improves the temperature resistance of the clean fracturing fluid. It is expected that the fluid can not only be used to improve oil recovery in tight oil reservoirs, but also be used to solve the leakage problem in CO2 storage underground.

Bubble breaks up and coalesces continuously during migration in reservoirs, which determines the size distribution of bubbles. As a key parameter of foam technology, the bubble size greatly affects foam stability and plugging performance in the reservoir. Aiming to solve the problem of poor stability of ordinary foam under reservoir conditions, in this study, a high-stability foam for profile control was prepared using dispersed particle gel particles as a foam stabilizer. The characteristics of foam were mainly investigated by the modified Ross-Miles method and microfluidic experiments. The obtained results showed that the foam reinforced by dispersed particle gel particles had a longer half-life under reservoir conditions. It is easier to break up from parent bubbles to daughter bubbles during the migration, which can form foam with higher stability in the porous media. The average size of the daughter bubbles decreased with increasing liquid-phase flow rate, pore-throat ratio and capillary number. The average size varied with the capillary number in a power-law form. Because of the viscoelastic interfacial film and liquid-phase viscous network, the shear effect on the parent bubble in reinforced foam was increased when passing through the pore-throat structure with variable diameter. The large parent bubbles were more likely to break up into more small and stable daughter bubbles. And the interfacial film with higher mechanical strength makes it difficult for the daughter bubbles in reinforced foam to coalesce again. The results indicated that the reinforced foam had stronger dynamic stability and better plugging performance in the reservoir. This work revealed the breakup and coalescence mechanism of bubbles reinforced by dispersed particle gel particles in porous media and provided theoretical guidance for the application of foam technology in high water-cut reservoirs.

Superhydrophobic wettability inspired by the “lotus effect” is an intriguing property in nature, but it is rarely applied in oilfield development. Superhydrophobic nanomaterials can effectively solve the problem of “high injection pressure and insufficient water injection” in low permeability oilfields by changing the properties of the core surface, which is of great significance to the development of low permeability oilfields. Herein, we report a novel type of superhydrophobic nanoparticle (SHNP) simply modified by fluorinated long chains, and a stable nanofluid is successfully prepared by compounding surfactant. The prepared SHNP nanofluid has an excellent core drag reduction effect, and the drag reduction rate is 1.35 times that of conventional NPs under the same conditions. The SHNPs assemble on the core surface to form a large number of micro/nanorough structures, which can effectively reduce the surface roughness of the core. The PIV experimental results show that compared with the injection of pure water, the center flow velocity in the subsequent water flooding center increases by 98.27% after the injection of SHNPs nanofluid (the flow velocity decreases by 53.45% after the injection of NPs). Moreover, bubble probe AFM technology has successfully shown that bubbles can be captured through the SHNPs superhydrophobic interface to form a gaseous film. By using the barrier effect of the gaseous film, the liquid-solid interface is converted to a liquid-gas-solid interface, thereby reducing the large resistance caused by the direct contact between the liquid and solid. Such SHNPs with simple modification and low cost have broad application potential in oilfield development.

Compound surfactant system has been extensively studied in enhanced oil recovery (EOR) as the synergistic effect of mixed surfactants can increase the density of surfactants distributed at the oil/water interface, enhancing the interfacial activity and decreasing the interfacial tension. The system can further increase the capillary number and enhance oil recovery for oil-wet reservoirs. Studying the interactions between surfactant molecules is of great significance to the enhancement of practical application performances. In this study, N, N-dihydroxyethyl alkyl amide (CDEA), and Alkylphenol polyoxyethylene carboxylate (APEC) with different EO numbers were mixed to prepare a binary compound oil displacement system. The influence of the EO number on the synergistic effect of the CDEA/APEC system and the EOR potential was measured by interfacial tension, nanomechanical tests and oil-displacement experiments. The results indicate a synergistic effect between CDEA and APEC due to the formation of hydrogen bonds between the hydroxyl groups of CDEA and the EO chains of APEC. An optimal synergistic effect in the system was obtained when the EO number was four. The CDEA/APEC-4 system exhibited an oil/water interfacial tension decrease to 10(-2) mN/m at 75 degree celsius and the oil recovery was 57.14 %, which was increased by 19.2 % compared to primary water flooding. However, a longer EO chain length weakened the interaction forces between CDEA and APEC, which diminished the synergistic effect of the system, leading to an increase of the interfacial tension. Due to the flexibility of the EO chain, the increase in the EO number leads to the bending of APEC molecules. The longer EO chain length weakened the interaction forces between CDEA and APEC, which diminished the synergistic effect of the system, leading to an increase of the interfacial tension. The oil-displacement experiment revealed that the EO chains changed the oil recovery and injection pressure by affecting the interfacial tension of the mixed system. This study has significant implications for the formulation design and optimization of agents for oilfield development.

In recent years, the liquid temporary plugging agent has drawn extensive attention, especially in the repeated fracturing operation for stimulating unconventional oil and gas reservoir production. This paper developed a novel self-degradable gel (SDG) as a liquid temporary plugging agent for high-temperature reservoirs. The gelation process, viscoelasticity, pressure-bearing capacity, self-degradation, and formation protection performance of the SDG were systematically investigated. Moreover, the gelation and self-degradation mechanism of the SDG were revealed by studying the viscosity variation and the microstructures. Considering the gelation time and gel strength, the composition of the SDG was optimized as 6.0-10.0 wt% monomer, 0.004-0.012 wt% initiator, and 0.2-0.4 wt% crosslinker. The SDG transformed from liquid to solid-like gel within 30 to 90 min at 90-130 degrees C. The rheological results showed that the duration of the low viscosity state exceeded 75 % of the total gelation process at high temperatures, which was conducive to the injection of the SDG. In addition, the viscosity of the SDG after gelation was more than 100 Pa(.)s, which ensured its effective plugging in fractures. The experimental results with fractured cores showed that the bearing pressure of the SDG remained above 30 MPa/ m in fracture with a width of 2.05-5.04 mm, which could meet the requirements of the repeated fracturing operation. Moreover, the SDG could spontaneously degrade from solid-like gel to liquid with a viscosity of lower than 10 mPa(.)s in 10-105 h at 90-130 degrees C. The broken-gel liquid could be completely displaced out of the fractured core, and the core damage rate was less than 5.0 %, which ensured the restoration of conductivity of the previously existing fractures. Micrographs showed that the dense three-dimensional network structure with high viscosity was formed by polymerization and crosslinking. Then, the acrylic acids in the polymer chain were broken at high temperatures, resulting in the gradual destruction of the gel and the spontaneous degradation of SDG.

Foam drainage gas recovery technology is a chemical method to solve the serious bottom-hole liquid loading in the middle and late stages of gas well production, and the optimization of foam drainage agents (referred to as FDAs) is the key to the technology. According to the actual reservoir conditions, a high-temperature and high-pressure (HTHP) evaluation device for FDAs was set up in this study. The six key properties of FDAs, such as HTHP resistance, dynamic liquid carrying capacity, oil resistance, and salinity resistance, were evaluated systematically. Taking initial foaming volume, half-life, comprehensive index, and liquid carrying rate as evaluation indexes, the FDA with the best performance was selected and the concentration was optimized. In addition, the experimental results were verified by surface tension measurement and electron microscopy observation. The results showed that the sulfonate compound surfactant (UT-6) had good foamability, excellent foam stability, and better oil resistance at high temperature and high pressure. In addition, UT-6 had stronger liquid carrying capacity at a lower concentration, which could meet the production requirement when the salinity was 80 000 mg/L. Therefore, compared with the other five FDAs, UT-6 was more suitable for HTHP gas wells in block X of the Bohai Bay Basin, whose optimal concentration was 0.25 wt %. Interestingly, the UT-6 solution had the lowest surface tension at the same concentration, with the generated bubbles being closely arranged and uniform in size. Moreover, in the UT-6 foam system, the drainage speed at the plateau boundary was relatively slower with the smallest bubble. It is expected that UT-6 will become a promising candidate for foam drainage gas recovery technology in HTHP gas wells.

Chemical viscosity reduction and cold production technology has the characteristics of low cost, low energy consumption, and low emission, which makes it suitable for gradually replacing thermal production as the main development method of heavy oil reservoirs. Most of the existing evaluation processes of viscosity reducers used in chemical viscosity reduction and cold production adopt the dynamic method of preparing O/W emulsions by high-speed shearing. However, high-speed shearing cannot be achieved in the contact process between heavy oil and the viscosity reducer in porous media. There is only a weak seepage shear force, which makes heavy oil self-diffuse in the viscosity reducer solution. Therefore, the existing methods cannot accurately evaluate the self-diffusion performance of viscosity reducers under quasistatic conditions. In this work, a method for evaluating the self-diffusion performance of a heavy oil viscosity reducer based on UV-Vis absorption spectroscopy is proposed, and the influence of various factors on the viscosity reduction effect and self-diffusion performance of a viscosity reducer is investigated. The results show that there is a good correspondence between the viscosity reduction effect and the self-diffusion performance. The viscosity reducer concentration, oil content, temperature, and emulsification time have obvious effects on the self-diffusion performance of the viscosity reducer. Based on the results of the orthogonal experiment, a self-diffusion performance prediction model of the viscosity reducer is established. The verification experiment results show that the model has good applicability. This research provides a new idea for accurately evaluating the self-diffusion performance of viscosity reducers under quasi-static conditions.

Foam technology is currently recognized as one of the most promising technical means to further enhance oil recovery. However, the poor stability of foam in harsh reservoirs with high temperatures limits the further application of foam fluids in oil fields. Based on the Pickering emulsion template method, this paper proposed a synthesis strategy for Janus nanographene oxide with aerophilic/hydrophilic characteristics as a novel foam stabilizer. A high-stability foam reinforced by Janus nanographene oxide was constructed. In addition, this paper clarified the relationship between foam stability and the interfacial characteristics of foam and revealed the probable mechanism by which Janus nanographene oxide enhances foam stability. The results showed that the synthesized Janus nanographene oxide has a typical two-dimensional lamellar structure with an obvious asymmetric characteristic. The negatively charged Janus nanographene oxide showed a small particle size, high zeta potential, high thermal stability, satisfactory amphiphilicity, and high interfacial adsorption, which was beneficial for enhancing foam stability at high temperatures. The foam stability was positively correlated with the interfacial viscoelastic modulus of the foam. Janus nanographene oxide was irreversibly adsorbed onto the gas-liquid interface, which increased the interfacial viscoelastic modulus, especially the interfacial elastic modulus increased from 2.94 mN center dot m(-1) to 16.21 mN center dot m(-1). As a result, the ability of the foam to resist deformation due to external forces was enhanced, which can be reflected in the enhancement of the foam stability. The half-life of foam at high temperature increased from 26 min to 49 min. An appropriate amount of Janus nanographene oxide can form a solid-like film with high mechanical strength on the gas-liquid interface and gradually fill the Plateau boundary of the foam. It can not only effectively reduce the drainage rate of the liquid film but also hinder gas diffusion between adjacent bubbles, which delays the further thinning of the film and coarsening behavior of the foam. Therefore, the constructed reinforced foam can be considered as a promising candidate for further enhancing oil recovery in high-temperature reservoirs, especially for steam channeling control. In addition, this work contributes to a better understanding of the mechanism by which Janus nanomaterials can enhance foam stability and provides theoretical guidance for the further application of foam technology. (c) 2022 Published by Elsevier B.V.

The breakthrough flow channel generated by formation heterogeneity has severely restricted oil recovery improvement, and its identification and control methods have received extensive attention. In this study, we developed a novel fluorescent dispersed particle gel (FDPG) for identifying and regulating breakthrough flow channels based on the dispersed particle gel (DPG). A copolymer of acryloyl fluorescein and acrylamide (PAMAF) was synthesized by free-radical copolymerization for the preparation of the FDPG. The fluorescence properties and identification method of FDPG were systematically investigated. The results showed that the FDPG had stable fluorescence properties, and its concentration showed a linear relationship with fluorescence intensity. The excitation and emission wavelengths of FDPG fluorescence fall within the interval that can avoid the influence of crude oil on its detection. FDPG can accurately reflect the migration of particles in the formation and avoid the chromatographic separation effect. FDPG has excellent injection and migration properties and can effectively control the high permeability layer after ageing. By analysing the output of the FDPG, breakthrough flow channels that exist between formation layers and within well groups can be effectively identified. FDPG provides a promising approach for identifying breakthrough flow channels and monitoring particle profile control agents.

Polyacrylamide-based drag reducers are an essential component of slickwater fracturing fluids and are used to reduce friction during the fracturing process. However, the elevated temperature accelerates the mechanical and oxidative degradation of polyacrylamide, resulting in a dramatic decrease in the drag reduction capability. To improve the temperature resistance of polyacrylamide, many researchers have focused on introducing rigid groups into the side chains of polyacrylamide. However, the improvement in the temperature resistance of polyacrylamide is limited. To address this problem, a novel water-in-water nanocomposite drag reducer, called ANS-PAA, was developed. ANS-PAA was synthesized by in-situ dispersion polymerization, which involved the use of amino-functionalized nano-silica, acrylamide, and 2-acrylamido-2-methylpropane sulfonic acid. The nanoparticles were linked to the polymer through hydrogen bonding and electrostatic interactions, which dramatically improved the thermal stability of ANS-PAA molecules. The drag reducer exhibits fast dissolving and strong temperature-resistant. Its dissolution time in tap water is 19 s and its drag reduction rate at 120 degrees C is 70.2 %. In addition, the nanoparticles embedded in the polymer network enhanced the strength of the structure. This study provides valuable insights into the development of drag reducers in slickwater fracturing fluids that more efficiently handle the high temperatures encountered in deep oil and gas reservoirs.

Insufficient mobility control capability and limited swept volume are the primary challenges faced by polymer flooding technology. In this work, a graphite oxide nanoparticle-reinforced polymer (GORP) flooding system was constructed. Compared with the conventional polymer (CP) flooding system, the GORP flooding system with 0.15% graphite oxide nanoparticles has a better viscosity increasing effect, shearing resistance and aging stability. In terms of mobility control capability, due to the reinforcing effect of graphite oxide nanoparticles on the three-dimensional polymer network structure, the GORP flooding system has a higher resistance factor and residual resistance factor than the CP flooding system in different permeability cores. In addition, the NMR online displacement experiment results further prove that the enhanced oil recovery performance of the GORP flooding system is more prominent, with a total recovery of 72.87%, which is 5.04% higher than that of the CP flooding system. The GORP flooding system may have the potential to become a long-term effective technology to control the water cut of oil wells.

In this work, molecular-level kinetic modeling was developed for the fluid catalytic cracking (FCC) naphtha olefin reduction process in a subsidiary riser. A transfer strategy for model parameters between different scale reactors was proposed. A molecular-level kinetic model was developed for a laboratory-scale fixed fluidized bed (FFB). The kinetic parameters were tuned using systematic experimental data of FFB under different conditions. Then, a molecular-level process model was built for a pilot riser. The kinetic parameter of the pilot riser model was transferred from the FFB model using only one scale-up experimental data to tune the transferring factors. The obtained riser model can accurately predict the fraction yield, naphtha composition, and temperature profile while the feedstock and operating conditions were changed.