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The wettability of the proppant is crucial in optimizing the flowback of fracturing fluids and improving the recovery of the produced hydrocarbons. Neutral wet proppants have been proven to improve the fluid flow by reducing the interaction between the fluid and the proppant surface. In this study, a lightweight amphiphobic proppant (LWAP) was prepared by coating a lightweight ceramic proppant (LWCP) with phenolic resin, epoxy resin, polytetrafluoroethylene (PTFE), and trimethoxy(1H,1H,2H,2H-heptadecafluorodecyl)silane (TMHFS) using a layer-by-layer method. The results indicated that the LWAP exhibited a breakage ratio of 2% under 52 MPa (7.5 K) closure stress, with an apparent density of 2.12 g/cm3 and a bulk density of 1.21 g/cm3. The contact angles of water and olive oil were 125° and 104°, respectively, changing to 124° and 96° after displacement by water and diesel oil. A comparison showed that the LWAP could transport over a significantly longer distance than the LWCP, with the length increasing by more than 80%. Meanwhile, the LWAP displayed notable resistance to scale deposition on the proppant surface compared to the LWCP. Furthermore, the maintained conductivity of the LWAP was higher than that of the LWCP after displacement by water and oil phases alternately. The modified proppant could minimize production declines during hydrocarbon extraction in unconventional reservoirs. [ABSTRACT FROM AUTHOR]

Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant–polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant–polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant–polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant–polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant–polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields. [ABSTRACT FROM AUTHOR]

Geochemical reactions are crucial for in situ CO2 mineralization underground associated with CO2‐enhanced oil recovery (CO2‐EOR) in a hydrocarbon reservoir. However, the presence of formation water and adsorbed oil on rocks generates physical barriers to CO2's access to mineral surfaces, which may yield impedance to CO2 mineral trapping that has yet to be accounted for. In this study, we mimic the dynamic oil detachment process using molecular dynamic (MD) simulation and analyze the influence of an adsorbed oil film on supercritical CO2 (scCO2) diffusion toward the mineral surface in the presence and absence of a water phase. Our results demonstrated a negative impact of water on oil film detachment by scCO2, which may weaken mineral reactions and is unfavorable for mineralized CO2 storage underground. Plain Language Summary: Carbon dioxide emission has been identified as one of the primary factors influencing global climate change. Storing CO2 underground while enhancing oil recovery is a promising technology that can effectively reduce costs for carbon capture, utilization, and storage (CCUS). Mineral trapping, that is, converting CO2 to carbonate minerals through CO2‐water‐mineral surface reactions, is one of the major mechanisms for CO2 storage. However, residual oil adsorbed on rock surfaces after CO2 injection into an oil reservoir yields a physical barrier for CO2 approaching mineral surfaces. CO2‐water‐oil‐mineral interactions have yet to be thoroughly understood. Therefore, we conducted a series of molecular dynamics simulations to mimic the dynamic oil detachment process and unveil the impact of water on oil film detachment by supercritical CO2. We found that the presence of water strengthens the interactions between the oil and rock surface, which may give rise to a substantial delay in oil film detachment and weaken mineral reactions. Our results provide significant implications for the mineralized storage of CO2 in a depleted oil reservoir and CO2‐enhanced oil recovery and its consequent sequestration. Key Points: CO2‐water‐oil‐rock interactions are investigated using molecular dynamics simulationsscCO2 can collapse the oil film and channel out a path for CO2 diffusionWater exhibits a negative impact on oil film detachment by scCO2 [ABSTRACT FROM AUTHOR]

The Henan Oilfield's medium-permeability blocks face challenges such as high temperatures and severe heterogeneity, making conventional flooding systems less effective. The starch gel system is an efficient approach for deep profile control in high-temperature reservoirs, while the nano-MoS2 system is a promising enhanced oil recovery (EOR) technology for high-temperature low-permeability reservoirs. Combining these two may achieve the dual effects of profile control and oil displacement, significantly enhancing oil recovery in high-temperature heterogeneous reservoirs. The basic performance evaluation of the combination system was carried out under reservoir temperature. Displacement experiments were conducted in target blocks under different permeabilities and extreme disparity core flooding to evaluate the combination system's oil displacement effect. Additionally, the displacement effects and mechanisms of the starch gel and nano-MoS2 combination system in heterogeneous reservoirs were evaluated by simulating interlayer and intralayer heterogeneity models. The results show that the single nano-MoS2 system's efficiency decreases with increased core permeability, and its effectiveness is limited in triple and quintuple disparity parallel experiments. After injecting the starch gel–nano-MoS2 combination system, the enhanced oil recovery effect was significant. The interlayer and intralayer heterogeneous models demonstrated that the primary water flooding mainly affected the high-permeability layers, while the starch gel effectively blocked the dominant channels, forcing the nano-MoS2 oil displacement system towards unswept areas. This coordination significantly enhanced oil displacement, with the combination system improving recovery by 15.33 and 12.20 percentage points, respectively. This research indicates that the starch gel and nano-MoS2 combination flooding technique holds promise for enhancing oil recovery in high-temperature heterogeneous reservoirs of Henan Oilfield, providing foundational support for field applications. [ABSTRACT FROM AUTHOR]

The CO2-responsive Pickering emulsions employed have garnered considerable attention across enhanced oil recovery agents, delivery of crude, and oilfield-produced fluid treatment. This study focuses on the design of an innovative type of Janus nanoparticle (JNP) and its application in the construction of CO2 stimuli-responsive Pickering emulsions. The emulsion stabilized by JNPs demonstrates swift phase separation subsequent to the injection of CO2. Furthermore, the mechanism of the CO2-stimulated responsiveness enabled by the JNPs was proposed. Based on the Schiff reaction, the synthesis of JNPs was achieved successfully via the Pickering emulsion template method. The properties of the JNPs were studied using various analytical techniques such as Fourier transform infrared, thermogravimetric analysis, scanning electron microscopy, transmission electron microscopy, etc. The developed responsive system, composed of JNPs and sodium oleate surfactant, showed high interfacial activity at the oil/water interface. The study revealed that the responsive system-stabilized Pickering emulsions could remain stable at 70 °C and room temperature for 24 and 120 h, respectively. Furthermore, the introduction of CO2 for 1.5 min resulted in phase separation because the nanoparticles lost the amphiphilic nature, triggering a significant decrease in interfacial activity and the protonation of sodium oleate surfactant inactivation. Then, the particles started to desorb from the interface. This study proposes a convenient, simple, and cost-effective approach for preparing fast CO2-responsive Pickering emulsions. It provides novel insights into the advancement of oilfield-produced fluid treatment, transportation of crude oil, and enhanced oil recovery. [ABSTRACT FROM AUTHOR]

This work focuses on the development of a novel high-temperature microemulsion for enhanced oil recovery in tight oil reservoirs. Microemulsions are a type of mixture that has properties of both liquids and solids; they have shown significant potential for improving oil recovery through spontaneous imbibition. Herein, a high-temperature-tolerant lower-phase microemulsion using a microemulsion dilution method was developed. The properties and morphological characteristics of the microemulsion were evaluated and proposed a mechanism for enhanced spontaneous imbibition oil recovery using imbibition tests and CT scanning technology. The results of the study showed that the optimum concentration of the microemulsion was 0.2 wt% and that it had good thermal stability, small droplet size, lower interfacial tension, good wettability alteration ability, and minimum adsorption loss. The imbibition and CT experiments demonstrated that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. The study concludes that the solubilization coefficient and self-driving force were defined and calculated to quantitatively analyze the imbibition mechanisms and the results showed that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. [ABSTRACT FROM AUTHOR]

Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs. [ABSTRACT FROM AUTHOR]

Recently, much attention has been directed toward nanofluids' applications for enhanced oil recovery (EOR). Here, amphiphilic molybdenum disulfide (KH550-MoS2) nanosheets are synthesized using a hydrothermal approach. The physicochemical properties and EOR potential of ultralow concentration KH550-MoS2 nanofluids are systematically investigated at Changqing Oilfield (China) reservoir conditions (temperature∼55 °C and salinity∼7.8 × 104 mg/L). Interfacial tension (IFT), wettability alteration and emulsion stability are characterized to evaluate the physicochemical properties of KH550-MoS2 nanofluids. The results show that ultralow concentration KH550-MoS2 nanofluid (50 mg/L) can decrease IFT to 2.6 mN/m, change contact angle (CTA) from 131.2° to 51.7° and significantly enhance emulsion stability. Core flooding experiments are conducted to determine the dynamic adsorption loss law and oil displacement efficiency of KH550-MoS2 nanofluid. Results indicate that the cumulative produced KH550-MoS2 nanosheets ratio to total injected KH550-MoS2 nanosheets (CNR) reaches 91.5% during flooding in a low permeability reservoir. Moreover, ultralow concentration KH550-MoS2 nanofluid can increase oil displacement efficiency by 14% after water driven. This work offers a new amphiphilic nanofluid with high efficiency for EOR. [ABSTRACT FROM AUTHOR]

Tahe Oilfield, located in northwest China, is an unconventional fracture–vuggy carbonate reservoir. The foam-assisted nitrogen gas flooding technology has been proven to be a potential EOR technology. However, the flow behaviors of foam-assisted nitrogen gas in fracture–vuggy structures are not clear due to the complex fracture–vuggy structures and their strong heterogeneity. In this work, a three-dimensional visualized fracture–vuggy model is designed and fabricated to investigate the fluids behaviors of foam-assisted N2 flooding and classify the residual oil types after foam-assisted N2 flooding. Experimental results reveal that foam slug can enlarge the sweep efficiency, suppress the formation of nitrogen gas channeling, and detach the oil film. Additionally, the evolution processes of the gas–oil and oil–water interfaces are investigated and analyzed. Moreover, the residual oil types after foam-assisted N2 flooding and nitrogen gas flooding, respectively, are classified and summarized. Compared to nitrogen gas flooding after water flooding, 12.36% more oil can be recovered through foam-assisted N2 flooding. This work further studies the fluid flow behaviors of foam-assisted N2 in the three-dimensional visualized fracture–vuggy carbonate model and also confirms the previous achievements. [ABSTRACT FROM AUTHOR]

The carbon dioxide (CO2) injection is the promising enhanced oil recovery technique used in low permeability reservoirs. The presence of high permeability fractures along the matrix leads to poor sweep efficiency and gas channeling effect. The CO2 responsive mobility control gels could be a potential solution to mitigate the gas channeling effects. This work showcases the straightforward method to prepare a CO2 responsive gel by mixing aqueous suspension of nanocellulose and ethylenediamine. The addition of CO2 leads to protonation of amine which enhances the ionic strength of the solution. This promotes the agglomeration of nanocellulose to form gel. The rheological properties of the gel were studied and found to have interesting mechanical property. And the micromodel is used to visualize the mobility control phenomenon of the as prepared gel. The core flooding experiment proves that the synthesized gels were effective in low permeable cores. [ABSTRACT FROM AUTHOR]

Foam-assisted steam flooding is a promising technique to alleviate gas channeling and enhance sweep efficiency in heterogeneous heavy-oil reservoirs. However, long-term foam stabilization remains problematic at high temperatures. Three-phase foam (TPF), containing dispersed solid particles, has been proposed to improve foam stability under harsh reservoir conditions. We fabricated a novel TPF system by adding ultrafine fly ash particles, as well as high-temperature resistant microspheres with an adhesive coating layer. This work aims at assessing the ability of the generated TPF in controlling steam channeling and enhancing oil recovery. Static and core flood tests were performed to evaluate foam strength and stability. Our results suggested a stronger foamability at a lower consolidation agent concentration, while a longer half-life period of foam and settling time of solid particles at a larger consolidation agent concentration were observed. Bubbles suspended independently in the liquid phase, with sizes varying from 10 to 100 μm, smaller than that of the conventional foam, suggesting a significant enhancement of foam dispersity and stability. The plugging rate was close to 90% when the temperature was as high as 300 °C, demonstrating a well-accepted plugging effect under high temperatures. A larger pore volume injection of TPF yielded a higher EOR in parallel cores, which substantiated the effectiveness of the three-phase foam system in sealing high-permeability channels. [ABSTRACT FROM AUTHOR]

Much attention has been directed toward amphiphilic nanosheets in diverse applications owing to their remarkable properties. In this work, the rhamnolipid-molybdenum disulfide nanosheets, environmentally friendly biological-amphiphilic-nanosheets (BANs), are prepared through the one-step simple hydrothermal method. The ultralow concentration of BANs (0.005 wt %), as a solid emulsifier, can emulsify crude oil and stabilize the size of emulsions (oil in water) within 1.2 μm. The adsorption of BANs to the oil–water interface improves the stability of the BANs emulsion, and it both reduces interfacial tension and increases interfacial film strength. Tremendous desorption energy (thousands of KBT) is required to remove a single BAN from the interface to the bulk phase. Besides, BANs can turn an oil-wet surface into an intermediate-wet surface and spread to exfoliate oil film on the solid surface. The evolution of the three-phase contact line experiences two stages: a steep stage and a gentle stage. The spreading behaviors are due to an imbalance between the surface forces and structuring disjoining pressure at the confinement region (wedge film). Moreover, 25.3% of additional oil recovery was observed from the flooding of an ultralow concentration of BANs nanofluid (0.005 wt %) in a natural outcrop core, which is 2.5 mD in permeability at experimental conditions: 120 °C and around 25 × 104 mg/L in salinity. The high tolerance of rhamnolipid-molybdenum disulfide nanosheets to high temperature and harsh salinity is because of synergism between MoS2 nanosheets and rhamnolipid molecules. Additional residual oil reduction is due to a combination of multiple effects such as crude oil emulsification, wettability alteration, interfacial tension reduction, and formation of structuring disjoining pressure. This study presents the possibility to enhance oil recovery in low-permeability reservoirs with harsh conditions. [ABSTRACT FROM AUTHOR]

Fines migration induced by injection of low-salinity water (LSW) into porous media can lead to severe pore plugging and consequent permeability reduction. The deep-bed filtration (DBF) theory is used to model the aforementioned phenomenon, which allows us to predict the effluent concentration history and the distribution profile of entrapped particles. However, the previous models fail to consider the movement of the waterflood front. In this study, we derive a stochastic model for fines migration during LSW flooding, in which the Rankine-Hugoniot condition is used to calculate the concentration of detached particles behind and ahead of the moving water front. A downscaling procedure is developed to determine the evolution of pore-size distribution from the exact solution of a large-scale equation system. To validate the proposed model, the obtained exact solutions are used to treat the laboratory data of LSW flooding in artificial soil-packed columns. The tuning results show that the proposed model yields a considerably higher value of the coefficient of determination, compared with the previous models, indicating that the new model can successfully capture the effect of the moving water front on fines migration and precisely match the effluent history of the detached particles. [ABSTRACT FROM AUTHOR]

CO2 has strong abilities of oil swelling and viscosity reduction for heavy oil extraction, N2 is a preferable gas media for pressure maintenance, and their mixture is then considered as an alternative method for enhanced oil recovery (EOR) in a pressure-depleted heavy oil reservoir. PVT analysis and cyclic gas injection experiments are conducted to reveal EOR mechanisms for CO2/N2 mixture, and five different CO2/N2 molar ratios (1:0 (pure CO2), 4:1, 7:3, 1:1, and 0:1 (pure N2)) are designed in this paper. PVT analysis shows that the changes of oil properties including saturation pressure, volume factor, and viscosity are highly related to CO2/N2 ratio of the mixture, and a higher CO2/N2 ratio can always lead to better gas/oil interactions. When CO2/N2 ratio is higher than 7:3, the viscosity can reduce to less than 60% of the initial oil viscosity. Gas injection experimental results show that 4:1 mixture can achieve an oil recovery of 17.31%, which is close to the recovery obtained by pure CO2. For the pressure-depleted oil reservoir, simultaneous CO2/N2 injection or N2 followed by CO2 injection is suitable injection mode for the mixture. With such a design of CO2/N2 mixture, an optimized EOR effect can be achieved with gas/oil interactions dominated by CO2 coupled with energy supplement provided by N2. A pilot test of CO2/N2 mixture injection is successfully conducted in a test well, and an oil increment of 337 t is obtained after 40,000 m3 of N2 injection followed by 80,000 m3 of CO2 injection. [ABSTRACT FROM AUTHOR]

Traditional polymeric microsphere has several technical advantages in enhancing oil recovery. Nevertheless, its performance in some field application is unsatisfactory due to limited blockage strength. Since the last decade, novel core-shell microsphere has been developed as the next-generation profile control agent. To understand the expansion characteristic differences between these two types of microspheres, we conduct size measurement experiments on the polymeric and core-shell microspheres, respectively. The experimental results show two main differences between them. First, the core-shell microsphere exhibits a unimodal distribution, compared to multimodal distribution of the polymeric microsphere. Second, the average diameter of the core-shell microsphere increases faster than that of the polymeric microsphere in the early stage of swelling, that is, 0–3 days. These two main differences both result from the electrostatic attraction between core-shell microspheres with different hydration degrees. Based on the experimental results, the core-shell microsphere is suitable for injection in the early stage to block the near-wellbore zone, and the polymeric microsphere is suitable for subsequent injection to block the formation away from the well. A simple mathematical model is proposed for size evolution of the polymeric and core-shell microspheres. [ABSTRACT FROM AUTHOR]

Problems such as high permeability, serious heterogeneity, and ineffective water flooding exist in developing offshore oil fields. Integrating modified starch gel as profile control agent and foam to displace oil was investigated to improve production problems. Physical models with in-layer and interlayer heterogeneity, as well as different permeability ratios, were used in the physical simulation experiments. The feasibility and mechanism of this combined technology were discussed in detail. Experimental results indicated that the viscoelastic-modified starch gel with high viscosity could effectively block the high permeability channels, making foam migrate uniformly in the medium, and mobilize the remaining oil in the low permeability layers. For inner heterogeneous models, starch gel blocked the high permeability layer, as well as improved the sweeping volume of nitrogen foam. In addition, at permeability ratios exceeding 40, the foam sweeping efficiency and oil displacement effect became less significant. For interlayer heterogeneous models, the starch gel effectively blocked the high permeability layer. Based on the experimental results and theoretical analysis, the sweeping volume and displacement mechanism of the synergistic effects were discussed. The laboratory results can provide reference for optimizing nitrogen foam flooding and improving oil displacement. [ABSTRACT FROM AUTHOR]

In the middle of the last century, American scientists put forward the concept of capillary number and obtained the relation curve between capillary number and residual oil through experiments. They revealed that the corresponding residual oil saturation decreased with increasing of capillary number; after capillary number reached up to a limit, residual oil saturation would become stable and did not decrease. These important achievements laid a theoretical base for enhanced oil recovery with chemical flooding. On the basis of the theory, scholars developed chemical flooding numerical simulation software UTCHEM. During the numerical simulation study of combination flooding, the authors found that as the capillary number is higher than the limit capillary number, the changes of the residual oil saturation along with the capillary number differ from the classical capillary number curve. Oil displacement experiments prove that there are defects in classic capillary number experimental curve and it is necessary to mend and improve. Capillary number 'calculation' curve is obtained with a method of numerical simulation calculation and a complete description of capillary number curve is provided; On this basis, combination flooding capillary number experimental curve QL is obtained through experiments, which is different from the classical capillary curve; and based on which, an expression of corresponding combination flooding relative permeability curve QL is given and the corresponding relative permeability parameters are determined with experiments. Further oil displacement experiment research recognizes the cause of the singular changes of the capillary number curve. 'Combination flooding capillary number experimental curve QL' and 'combination flooding relative permeability curve QL' are written in combination flooding software IMCFS, providing an effective technical support for the application of combination flooding technical research. [ABSTRACT FROM AUTHOR]

Introduction. Converging evidence suggests that PDE-4 (phosphodiesterase subtype 4) plays a crucial role in regulating cognition via the PDE-4-cAMP cascade signaling involving phosphorylated cAMP response element binding protein (CREB). Objective. The primary endpoint was to examine the neurocognitive effects of extract Sceletium tortuosum (Zembrin) and to assess the safety and tolerability of Zembrin in cognitively healthy control subjects. Method. We chose the randomized double-blind placebo-controlled cross-over design in our study. We randomized normal healthy subjects (total n = 21) to receive either 25mg capsule Zembrin or placebo capsule once daily for 3 weeks, in a randomized placebo-controlled 3-week cross-over design. We administered battery of neuropsychological tests: CNS Vital Signs and Hamilton depression rating scale (HAM-D) at baseline and regular intervals and monitored side effects with treatment emergent adverse events scale. Results. 21 subjects (mean age: 54.6 years ± 6.0 yrs; male/female ratio: 9/12) entered the study. Zembrin at 25mg daily dosage significantly improved cognitive set flexibility (P < 0.032) and executive function (P < 0.022), compared with the placebo group. Positive changes in mood and sleep were found. Zembrin was well tolerated. Conclusion. The promising cognitive enhancing effects of Zembrin likely implicate the PDE-4-cAMP-CREB cascade, a novel drug target in the potential treatment of early Alzheimer's dementia. [ABSTRACT FROM AUTHOR]

The flow characteristics of deionized water in microtubes with diameters ranging from 2 to 30 µm are investigated. The experimental results show that the flow characteristics in microtubes with diameters of 16 pm and larger ones are in agreement with the classical theory. However, as the diameters are decreased to 5 and 2 µm, the nonlinear flow characteristics prevail and the results indicate significant departure of flow characteristics from the predictions of the conventional theory, and the smaller the diameters, the larger the departure. As the Reynolds number increases, the degree of nonlinear flow characteristics decrease gradually and the experimental results are approximately equal to the theoretical expectation. The minimum Reynolds number in this study is only 2.46×10-5. [ABSTRACT FROM AUTHOR]

With the gradual declining of oil increment performance of CO2 huff-and-puff wells, the overall oil exchange rate shows a downward tendency. In this regard, CO2 synergistic huff-and-puff technologies have been proposed to maintain the excellent effect and extend the technical life of such wells. However, there is no specific research on the mechanism and synergistic mode of CO2 huff and puff in horizontal wells. This study aims to establish the synergistic mode and determine the adaptability and acting mechanism of CO2 synergistic huff and puff. Three synergistic huff-and-puff modes are proposed based on the peculiarity of the fault-block reservoir's small oil-bearing area and broken geological structure. We establish three typical CO2 synergistic huff-and-puff models and analyze the influence of different geological and development factors on the huff-and-puff performance with numerical simulation. Each factor's sensitivity is clarified, and the enhanced oil recovery (EOR) mechanism of CO2 synergistic huff and puff is proposed. The sensitivity evaluation results show that the reservoir rhythm, inter-well passage, well spacing, high-position well liquid production rate, and middle-well liquid production rate are extremely sensitive factors; the stratum dip and injection volume allocation scheme are sensitive factors; and the relationship with structural isobaths is insensitive. The EOR mechanism of synergistic huff and puff includes gravity differentiation, supplementary formation energy, CO2 forming foam flooding, and coupling effect of production rate and oil reservoirs. The implementation conditions of the two-well cooperative stimulation mode are the simplest. The two-well model is suitable for thick oil layers with a positive rhythm and large formation dip. The single-well mode requires no channeling between the wells, and the multi-well mode requires multi-well rows and can control the intermediate well's fluid production rate. Field application at C2X1 block shows a good performance with a total oil increment of 1280 t and an average water-cut reduction of 57.7%. [ABSTRACT FROM AUTHOR]

The objectives of the work were to establish a new method of evaluating emulsifying property of ASP system, design a new-type ASP system without ultra-low interfacial tension (IFT) based on its emulsifying property, and test its capability to enhance oil recovery. A new-type ASP system without ultra-low IFT was designed. The composite performance indexes of the new-type ASP system named formula 1 and conventional ultra-low IFT ASP system named formula 2 applied in Daqing oilfield were evaluated. The Turbiscan Stability Index (TSI) parameter was utilized to characterize the stability of emulsions. Also, the emulsions were evaluated in terms of droplet size distribution, ζ potential, and rheology. The average droplet sizes of formula 1 emulsion and formula 2 emulsion were 4.6 μm and 11.4 μm respectively. Results showed that formula 1 had a better emulsifying power, a better stability of emulsion with lower TSI, smaller average droplet size, and higher absolute value of ζ potential than formula 2; thus, it had a higher composite performance index compared with formula 2. Furthermore, the formula 1 emulsion viscosity gave values higher than the viscosity of formula 2 emulsion. The experimental results showed that the additional oil recovery of formula 1 was always higher than that of formula 2. The non-ultra-low IFT ASP system with better emulsifying property had an approximately similar effect on enhanced oil recovery compared with the conventional ultra-low IFT ASP system. This research examines and analyzes the new outcomes from implementing the new-type ASP system without ultra-low IFT to improve oil recovery. Ultimately the gained results from this work indicate that the new-type ASP system can be applied to enhance oil recovery, and project a roadmap for ongoing and future work; however, more investigations are required to be conducted. [ABSTRACT FROM AUTHOR]

The purpose of this experimental study is to evaluate the efficiency and performance of gas huff-n-puff in the single well on recovery of light oil from a multi-well fractured-cavity reservoir and to reveal the feasibility of gas mediums huff-n-puff. In order to reveal the production performance characteristics and mechanisms of gas huff-n-puff on activating the remaining oil, a visualized and pressure resistant two-dimensional (2D) fractured-cavity model and a three-dimensional (3D) multi-wells model were designed and fabricated respectively based on the similarity theory. With the simulated oil and brine reservoir samples in Tahe oilfield, five groups of tests in 3D model and five groups in 2D model were performed, each of which included bottom water energy depletion driving, gas injection stage, soaking stage, and gas puff stage. The production performances of N2, CO2, and N2/CO2 mixture huff-n-puff in the 3D model were firstly analyzed. Then the remaining oil recovery principles of each gas were compared and analyzed in the 2D model. Finally, the influence of gas injection position was studied both in the 2D and 3D models. The experiment results from 3D model demonstrated that higher oil recovery factor could be achieved through N2 huff-n-puff which had shown enormous advantages than CO2 and N2/CO2 mixture. Furthermore, the results from 2D model indicated that there were four types of the remaining oil, all of which could be recovered through N2 huff-n-puff if it was implemented in the relative low-position well. The results from experiments on gas injection position conducted in the 3D physical model demonstrated the better oil recovery effect if N2 was injected in low-position well which was consistent with the results concluded in the 2D model. This paper confirmed the effectiveness and advantages of N2 huff-n-puff compared with CO2 and gas mixture in the light oil-saturated fractured-cavity reservoir. [ABSTRACT FROM AUTHOR]

The purpose of this experimental study is to evaluate the efficiency and performance of gas huff-n-puff in the single well on recovery of light oil from a multi-well fractured-cavity reservoir and to reveal the feasibility of gas mediums huff-n-puff. In order to reveal the production performance characteristics and mechanisms of gas huff-n-puff on activating the remaining oil, a visualized and pressure resistant two-dimensional (2D) fractured-cavity model and a three-dimensional (3D) multi-wells model were designed and fabricated respectively based on the similarity theory. With the simulated oil and brine reservoir samples in Tahe oilfield, five groups of tests in 3D model and five groups in 2D model were performed, each of which included bottom water energy depletion driving, gas injection stage, soaking stage, and gas puff stage. The production performances of N2, CO2, and N2/CO2 mixture huff-n-puff in the 3D model were firstly analyzed. Then the remaining oil recovery principles of each gas were compared and analyzed in the 2D model. Finally, the influence of gas injection position was studied both in the 2D and 3D models. The experiment results from 3D model demonstrated that higher oil recovery factor could be achieved through N2 huff-n-puff which had shown enormous advantages than CO2 and N2/CO2 mixture. Furthermore, the results from 2D model indicated that there were four types of the remaining oil, all of which could be recovered through N2 huff-n-puff if it was implemented in the relative low-position well. The results from experiments on gas injection position conducted in the 3D physical model demonstrated the better oil recovery effect if N2 was injected in low-position well which was consistent with the results concluded in the 2D model. This paper confirmed the effectiveness and advantages of N2 huff-n-puff compared with CO2 and gas mixture in the light oil-saturated fractured-cavity reservoir. [ABSTRACT FROM AUTHOR]

CO2 and N2 injection is an effective enhanced oil recovery technology in the oilfield especially for low-permeability and extra low-permeability reservoirs. However, these processes can induce an asphaltene deposition during oil production. Asphaltene-deposition-induced formation damage is a fairly severe problem. Therefore, predicting the likelihood of asphaltene deposition in reservoir conditions is crucial. This paper presents the results of flash separation experiments used to investigate the composition of crude oil in shallow and buried-hill reservoirs. Then, PVTsim Nova is used to simulate the composition change and asphaltene deposition of crude oil. Simulation tests indicate that the content of light components C1-C4 and heavy components C36+ decrease with increasing CO2 and N2 injection volumes. However, the extraction of CO2 is significantly stronger than that of N2. In shallow reservoirs, as the CO2 injection volume increases, the deposition pressure range decreases and asphaltenes are easily deposited. Conversely, the asphaltene deposition pressure of crude oil injected with N2 is higher and will not cause serious asphaltene deposition. When the CO2-N2 injection ratio reaches 1:1, the deposition pressure range shows a significant transition. In buried-hill reservoirs, asphaltene deposition is unlikely to occur with CO2, N2, and a gas mixture injection. [ABSTRACT FROM AUTHOR]