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In this study, a compound surfactant system composed of alkyl polyglucoside (APG) and amine oxide (OAE) was formulated to synergistically stabilize the oil-in-water emulsion for enhanced oil recovery (EOR). Dewatering ratio, droplet size distribution, interfacial tension (IFT), emulsion stability, and microscopic displacement performance of the compound system were investigated. The smallest emulsion droplet size and lowest IFT, indicating the presence of the most stable emulsion, are observed when the total mass concentration and the mass ratio of APG/OAE are 0.5 wt % and 7:3, respectively. The oil/water interfacial film is more compact, which is attributed to the electrostatic attraction. Meanwhile, the formation of an intermolecular hydrogen bond between APG and OAE molecules is beneficial for improving the strength of the interfacial film. Moreover, the microscopic flooding experiment was conducted with a microvisual model, indicating that the formulated compound system can effectively emulsify the residual oil and enhance oil recovery through trapping and carrying mechanisms. Hence, the compound surfactant system could serve as an ideal alternative in the chemical EOR.

The nanofluid prepared by spherical nanoparticles has a good enhanced oil recovery effect in low-permeability reservoirs. However, a huge adsorption loss has been produced in the process of oil displacement, reducing the oil recovery and increasing the production cost. In this paper, the static adsorption experiments under different influence factors, the dynamic desorption experiment on porous media, and the core flooding experiment are carried out with the nanofluids prepared by self-developed amphiphilic nanosheets (ODA-MoS2). Furthermore, the laws of adsorption kinetics and thermodynamics of the ODA-MoS2nanofluid on the porous media surfaces are proposed, and the effect on improving oil recovery is clarified ulteriorly. The results show that the physical adsorption of the system on the surface of oil sand is caused by diffusion (concentration difference), electrostatic interaction, and hydrogen bonding. There is a monolayer adsorption existing on the porous media surface, which is consistent with Langmuir isothermal adsorption model. The salinity and temperature have an inhibitory effect on the adsorption of the ODA-MoS2nanofluid; the adsorption capacity increases with the increase in concentration and reaches the equilibrium value of 1.68 mg/g at 75 mg/L. Moreover, the adsorption rate of the ODA-MoS2nanofluid is the lowest, only 14.71% compared to that of SiO2, whereas the oil recovery increases by 18.59% compared to primary water flooding under the concentration of 75 mg/L. Therefore, the ODA-MoS2nanofluid with a lower adsorption capacity is more effective in improving oil recovery in low-permeability reservoirs, and it is expected to be applied on a large scale for oil extraction in low-permeability reservoirs.

Geochemical reactions are crucial for in situ CO2mineralization 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 CO2mineral 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 CO2storage underground. Carbon dioxide emission has been identified as one of the primary factors influencing global climate change. Storing CO2underground 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 CO2to carbonate minerals through CO2‐water‐mineral surface reactions, is one of the major mechanisms for CO2storage. However, residual oil adsorbed on rock surfaces after CO2injection into an oil reservoir yields a physical barrier for CO2approaching 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 CO2in a depleted oil reservoir and CO2‐enhanced oil recovery and its consequent sequestration. CO2‐water‐oil‐rock interactions are investigated using molecular dynamics simulationsscCO2can collapse the oil film and channel out a path for CO2diffusionWater exhibits a negative impact on oil film detachment by scCO2 CO2‐water‐oil‐rock interactions are investigated using molecular dynamics simulations scCO2can collapse the oil film and channel out a path for CO2diffusion Water exhibits a negative impact on oil film detachment by scCO2

Acidic fracturing fluids, such as zirconium cross-linked carboxymethyl hydroxypropyl guar gum (CMHPG), can not only adapt to formations treated with CO2but also protect such formations from the damage that arises from the swelling and migration of clay particles during the hydrofracturing process. However, the shortcomings of uncontrollable viscosity growth and irreversible shear-thinning behavior limit the large-scale application of acidic fracturing fluids. In this work, a novel organic zirconium cross-linker was synthesized in the laboratory and applied under acidic conditions to control and delay cross-linking reactions. The ligands that were coordinated to the zirconium center were l-lactate and ethylene glycol. A CMHPG thickener was used at a low loading of 0.3% (approximately 25 pptg). Concentrated hydrochloric acid was utilized as a buffer to adjust the fracturing fluid pH to 3.0 for the majority of the tests and approximately simulate the pH attained in formations treated with CO2under high-temperature (HT)/high-pressure (HP) conditions. Moreover, surface-functionalized metallic-phase (1T) molybdenum disulfide (MoS2) nanosheets were employed to improve the rheological performance of the zirconium cross-linked CMHPG fracturing fluid. l-Cysteine was utilized as a modification reagent. The morphologies, structures, and properties of the fabricated functionalized 1T-MoS2(Cys-1T-MoS2) nanosheets were systematically characterized using transmission electron microscopy (TEM), scanning electron microscopy (SEM), Raman spectroscopy, X-ray diffraction (XRD), X-ray photoelectron spectroscopy (XPS), Fourier transform infrared spectroscopy (FTIR), and thermogravimetric analysis (TGA). The results of these characterization tests demonstrated the successful functionalization of the 1T-MoS2nanosheets with l-cysteine. Then, the effects of this new nanosheet-enhanced zirconium cross-linked CMHPG fracturing fluid system with different cross-linker and nanosheet loadings on gelation performance were systematically assessed through the Sydansk bottle testing method combined with a rheometer under controlled-stress or controlled-rate modes. Microscopic observations and gel-breaking, regained-permeability, and proppant-settling tests were also carried out to further evaluate the fracturing fluid properties of this new system. The results indicated that the nanosheet-enhanced fracturing fluid had a desirable delayed cross-linking property. Compared with the blank fracturing fluid (without nanosheet enhancement), the nanosheet-enhanced fracturing fluid had a much better shear tolerance, shear recovery, and proppant carrying performance. Micrograph observations showed that an even and fine three-dimensional (3D) network structure formed within the nanosheet-enhanced fracturing fluid sample. Additionally, in contrast to the alkaline system, the acidic nanosheet-enhanced zirconium cross-linked CMHPG fracturing fluid system had much less formation damage induced by gel residues and clay swelling and dispersions.

We systematically investigate the plugging performance and oil-displacement efficiency of the novel bilayer-coating microspheres (BCMS) designed for in-depth conformance control within heterogeneous hydrocarbon reservoirs. Visualization experiments on various glass models, as well as one- and two-phase core floods have been carried out at reservoir temperature and fluid salinity. Our results demonstrate that the rigid outer layer of BCMS can successfully protect its adhesive inner coating, enabling BCMS to transport deeply into porous media. Increasing particle concentration yields higher collision probability, leading to the formation of particle assembly that could effectively block pore throats in high-permeability channels and achieve more oil recovery in the low-permeability zones. It is also shown that as the BCMS slug size increases, the oil recovery asymptotically reaches a maximum value. A larger slug size cannot highly enhance the plugging performance yet significantly increase the resistance factor. A smaller permeability ratio of parallel cores leads to a narrower difference between the fractional flow rates. When the permeability ratio is two or lower, the fractional flow rates of parallel cores are both around 50%, yielding the best oil-displacement efficiency. BCMS exhibits promising application potential in production enhancement under reservoir conditions.

Oleic acid-modified titania (OA-TiO2) nanoparticles are synthesized for the application of enhanced oil recovery (EOR) in low-permeability reservoirs. The oleic acid is grafted onto the surface of titania by the esterification reaction under a specific condition. The well-dispersed OA-TiO2is expected to exhibit an excellent interfacial activity and a strong wettability alteration capability, owing to its amphiphilic features. This work aims to explore the potential of employing OA-TiO2in EOR and to unveil its mechanisms of displacing oil in porous media. The interfacial properties of OA-TiO2are systematically investigated by determining its interfacial tension and contact angle. A microfluidic test on a 2.5-D microfluidic model and a series of core floods are carried out to study the oil-displacement efficiency of OA-TiO2nanofluids. The experimental results demonstrate that oleic acid-modified titania nanoparticles show great potential in not only reducing the injection pressure but also enhancing hydrocarbon recovery in low-permeability reservoirs.

Amphiphilic nanosheets have gained great attraction in diverse applications owing to their unprecedented performance. In this paper, amphiphilic molybdenum disulfide (CTAB–MoS2) nanosheets were prepared through a one-step simple hydrothermal method, and the physicochemical properties were systematically investigated. The results showed that the CTAB–MoS2nanosheets displayed a distinct ultrathin flakelike structure and a lateral size in the range of 95 nm. More specifically, the presence of defect sites over the surfaces of MoS2nanosheets facilitated linkage with CTAB molecules, which made MoS2amphiphilic. Because of the amphiphilic nature, the CTAB–MoS2nanosheets could be steadily dispersed in water phase, reduce the oil–water interfacial tension, alter wettability of the solid surface, and stabilize emulsions at ultralow concentrations (50 mg/L). By observing and analyzing the interfacial behavior of CTAB–MoS2nanosheets in a simulated oil/brine system, it was found that CTAB–MoS2nanosheets could be adsorbed at the oil–water interface in the form of multilayer adsorption, and the adsorption layer (oil–water interfacial film) exhibited higher strength elasticity. This work provides a scalable method for preparing amphiphilic nanosheets and reveals the physicochemical properties of CTAB–MoS2amphiphilic nanosheets.

Phase behavior of shale gas or oil in nanopores is not yet well understood. One complexity comes from the fact that fluid adsorption can be significant in densely developed nanopores. A prediction process for the behavior of a ternary mixture (CH4, n-C4H10, and n-C8H18) and an actual Bakken oil in nanopore formation are performed by applying an adsorption-dependent Peng–Robinson equation of state, and the effect of adsorption and its induced critical properties shifts is discussed. Results indicate that the presence of adsorption could decrease the vapor–liquid equilibrium coefficient (K-value) and the vapor phase molar fraction for the confined ternary mixture, especially in the nanopores with a few nanometers. The shift in the saturation pressures of the ternary mixture and Bakken oil shows that the bubble point pressure and upper dew point pressure are depressed and the lower dew point pressure is increased with the synthetic effect of adsorption and critical shifts. The suppressed bubble point pressure well explains the production performance of a long-term flat producing gas/oil ratio in the Bakken reservoir. It should be noted that adsorption is relatively more dominant on bubble point pressure and critical shifts exhibit a greater influence on dew point pressure. For Bakken oil, the presence of adsorption increases the oil density and viscosity; however, critical shifts present conflicting impacts on oil density and viscosity, and the critical shifts are more dominant compared with fluid adsorption. This emphasizes the importance of considering both adsorption and critical shifts when describing phase behavior in shale nanopores.

The wettability condition of a rock’s surface is an enormous parameter for enhanced oil recovery (EOR) in low-permeability reservoirs. It determines the spreading of injected water and the adhesion of residual oil on rock surfaces. In this study, a new nanofluid composed of silica nanoparticles and rhamnolipid in brine was utilized as an effective agent to alter the wettability of a rock’s surface. In order to obtain rock surfaces with different initial wettabilities, hexamethyldisilazane (HMDS) was used for the sample preparation. The measurement of three-phase contact angles for water/air/rock and brine/oil/rock were performed to explore the contact situation between a rock surface and movable fluids, and the spontaneous imbibition test researched the process of oil recovery with nanofluid. By evaluating the experimental measurements, nanofluid showed a significant potential in wettability alteration from oil-wet toward water-wet state, which is an important mechanism for “scraping” oil drops from a rock surface during nano-EOR process. Moreover, a total of nine coreflooding tests were performed to investigate the effects of rock wettability on waterflooding and nanofluid flooding, respectively. The results revealed that an intermediate-wet state of a rock’s surface is in favor of the oil recovery especially for waterflooding, and nanofluid, resulting in an additional 5.3–6.8% increments in oil recovery compared to conventional waterflooding. In conclusion, nanofluids show a significant potential for EOR from low-permeability cores, implying a wide application in oil fields.

Microbial metabolic products, such as biosurfactants, bioemulsifiers, acids, solvents, and biogases, are useful for reducing the viscosity of heavy oils and enhancing oil recovery. Two heavy oil viscosity-reducing microorganisms, namely, SH-2 and SH-3, were selected from produced water which were collected from high-temperature reservoirs by enrichment culture technique. The screened bacteria produce biosurfactants and biogases that can biodegrade heavy crude oil components. The screened bacteria combined with indigenous bacteria were applied in a pilot test of microbial huff and puff. Temperature, porosity, and permeability of the reservoir were 50 °C, 14.32%, and 22 mD, respectively. After microbial treatment, the 50 °C degassing for crude oil viscosity of the produced oil was decreased from 750 to 634 mPa·s. Moreover, wax and resin–asphaltene contents of produced oil were reduced by 12.3% and 16.9%, respectively. The average oil production was improved from 2.2 to 3.5 t/day after microbial treatment. The production remained stable without the chemical viscosity reducer for 54 days. The analysis of bacterial community structure indicated that the number of bacteria species increased and that the microbial diversity was highly abundant. However, harmful microorganisms for microbe-enhanced oil recovery, such as sulfate-reducing bacteria, are inhibited during the progress of microbial huff and puff.

The effect of four different phenolic compounds (i.e., phenol, catechol, resorcinol, and hydroquinone) on the performance of organically cross-linked terpolymer gel systems at the temperature of 150 °C was investigated. The phenol-based gelant systems were not able to form visible bulk gels at this extremely high temperature because the cross-linked clusters between phenol and hexamethylenetetramine (HMTA) only contained a small number of hydroxyl groups for cross-linking reactions. The catechol- and hydroquinone-based gelants were able to form relatively strong bulk gels because the amount of the cross-linked clusters between these two phenolic compounds and HMTA increased significantly. This increment also contributed to the decrease of the grid sizes of the gel network structures and the emergence of dendritic structures on them, thereby significantly increasing the viscosity, storage modulus, and thermal stability of the obtained gels. However, these two gel systems could not be maintained for long; syneresis began after only 3–12 days of the systems being held at 150 °C. When phenol was replaced by resorcinol, bulk gels with excellent strength and long-term thermal stability were able to form at 150 °C. The use of the gelation mechanism of the cross-linking reactions between the terpolymer and different cross-linker systems can help researchers and petroleum engineers better understand the differences between the different cross-linker systems and thus develop more suitable polymer gel systems for water management in extremely high temperature reservoirs.

Polymer gel systems as water management materials have been widely used in recent years for enhanced oil recovery applications. However, most polymer gel systems are limited in their ability to withstand the harsh environments of high temperature and high salinity. Those polymer gel systems that can handle high-temperature excessive water treatments are reviewed in this paper and categorized into three major types: in situ cross-linked polymer gels, preformed gels, and foamed gels. Future directions for the development of polymer gel systems for high-temperature conditions are recommended. For excessive water management with temperatures from 80 to 120 °C, current polymer systems are substantially adequate. Polymer gel systems composed of partially hydrolyzed polyacrylamide (HPAM)/chromium can be combined with nanoparticle technology to elongate their gelation time and reduce the adsorption of chromium ions in the formation. Phenolic resin cross-linker systems have reasonable gelation times and gel strengths; however, more environmentally friendly cross-linkers should be developed to meet the increasingly stringent environmental requirements. For particle gels, the addition of functional monomer(s) can improve the antitemperature performance. When the applied temperatures reach 120 °C, inorganic cross-linker systems are no longer applicable, and the gelation time of organic cross-linking polymer gel systems and gel thermal stability will decrease significantly due to fast cross-linking reactions. During this period, retarders can be used to elongate the gelation time, and gel strength enhancers (e.g., cement, silica) can also be applied to improve the gel strength at such extremely high temperatures. Most importantly, novel polymers (e.g., ter- or tetrapolymers), functional monomers, and environmentally friendly cross-linkers need to be discovered and developed for polymer gel applications. Second cross-linking systems can be applied to further enhance the strength of the particle gels in harsh conditions. On the basis of these developments, foamed gels can be well-implemented in fractures and wormholes to save the amount of injected gels.

Low pH fracturing fluids, such as the transition metal cross-linked guar derivative, can reduce the formation damage caused by clay swelling and fines migration in hydraulic fracturing treatments. However, a major disadvantage of the fluids is the uncontrollable rapid viscosity development, especially cross-linking under a pH below 3.0. In this paper, a novel delayed organic zirconium cross-linker with lactate and ethylene glycol as ligands was designed to overcome the shortcoming. Carboxymethyl hydroxypropyl guar (CMHPG), which results in a low gel residue after breaking, was used as the polymer at low concentration. The impact of gelation parameters on the properties of zirconium-CMHPG gel system was systematically investigated using a Sydansk bottle-testing method combined with a controlled stress rheometer. Desirable gelation time delay with agreeable rheological performance could be obtained by optimizing the polymer and cross-linker concentrations even at a pH as low as 2.0. Uniformly and compactly generated 3D network microstructures could firmly lock the free water within the gel, which further improved the thermostability and acid-resistance of the system. Meanwhile, the structures could also maintain the viscoelasticity of the fluid at a high level to ensure the efficient transportation of the proppants. Proppant settling and gel breaking tests demonstrated that the low pH and low polymer concentration gel system generated fewer insoluble residues with an uncompromised suspension performance. Moreover, the formation damage evaluation revealed that the low pH fracturing fluid system produced a better return permeability than the high pH system.

An emulsion that can be fast and spontaneously formed in reservoirs will be greatly beneficial to the oil recovery improvement in low-permeability reservoirs. Herein, an ultralow interfacial tension spontaneous emulsification (SE) system consisting of a novel anionic alkyl polyglucoside sodium hydroxypropyl sulfonate surfactant (APGSHS) surfactant and a cationic cetyltrimethylammonium bromide (CTAB) surfactant was proposed and studied for low-permeability reservoirs. The spontaneous emulsions were characterized in terms of morphology and size distribution of droplets. Multiple-light scattering method was applied to evaluate the stability and dynamic instability mechanism of O/W emulsions. In addition, the viscoelasticity and shear-recovery performance of emulsions were also investigated. The combined SE systems can form the spontaneous emulsions via once bottom-up cycle, and the average droplets size of optimum emulsion with 6:4 molar ratio is ∼0.2 μm, which is small enough to migrate in the porous media at low-permeability reservoirs. Besides, the coalescence and creaming of oil droplets, as well as clarification thickness, are well-deferred. The viscoelasticity and shear-recovery capacity can also be improved with the presence of combined SE systems. The efficient interfacial activity and emulsion performances can be attributed to the strong electrostatic attraction between anionic and cationic surfactants, which enables the formation of a tighter arrangement film on an oil/water interface. Ultimately, the core flooding experiments show that the optimum SE system can effectively enhance oil recovery by 14.14% of the initial oil in place and significantly decrease the injected pressure. Hence, the newly formulated spontaneous emulsification system with anionic/cationic surfactants exhibit remarkable performances and can be used as an ideal candidate for EOR in low-permeability reservoirs.

To improve the efficiency of mobility control for polymer flooding, a novel thickening system was formed by adding medium-chain fatty alcohols to hydrophobically modified polyacrylamide (HMPAM) brine solutions. The interaction of HMPAM with fatty alcohols was investigated in terms of rheology properties, aggregate microstructure, and mobility control ability. The results show that n-octanol (C8OH) generates the best synergistic behavior with HMPAM compared to other fatty alcohols. More hydrophobic groups initially existing in either intramolecular or intermolecular association reassemble into larger aggregation structures due to the presence of C8OH. 750 mg·L–1C8OH could lead to an increase of viscosity by four times as that of individual HMPAM at low polymer concentration (1000 mg·L–1). Owing to the enhancement of the association structure, the HMPAM + C8OH system displays stronger shear-thinning behavior, higher viscoelasticity, and better resistance to salt and temperature. Polymer–brine displacement tests indicate that compared to other systems HMPAM + C8OH exhibits higher effective viscosity and moderate polymer retention in porous media, showing promising applicability in efficient mobility control for low-concentration polymer flooding.

Microparticles covered with double-layered coatings are developed for in-depth conformance control to enhance oil recovery within heterogeneous reservoirs. The proposed bilayer-coating microspheres (BCMS) can transport deeply into a porous media, owing to the rigid outer layer designed for protecting the adhesive inner coating. The objective of the present work is to characterize the adhesion property and the plugging behavior of BCMS at reservoir temperature and fluid salinity. A series of static and coreflood tests are conducted. BCMS exhibits resistance to high temperature and high salinity and shows a great ability of deep transport into porous media. A mathematical model for the deep-bed filtration of BCMS in porous media is developed, accounting for the limited retention concentration and the velocity difference between the suspended particles and the carrier fluid. Modeling results match the measured pressure drop histories in coreflood tests with high accuracy, which validates the proposed analytical model. BCMS shows promising potential for application in production enhancement in hydrocarbon reservoirs.

A stable emulsion can play an important role in displacing oil or controlling reservoir conformance for enhanced oil recovery (EOR) projects. In this work, visual inspection, multiple-light scattering, interfacial tension (IFT), and rheology were used to investigate the synergistic effects of regenerated cellulose and surfactant on oil-in-water emulsions stability and their efficiency in EOR. The results show that adding regenerated cellulose can significantly increase the stability of a surfactant emulsion, while decreasing the diameter, coalescence, and floatation of oil droplets. This can be attributed to the synergistic interactions between cellulose and surfactant, which enable them to form a tighter interface layer and slightly reduce the oil/water (O/W) IFTs. Moreover, in comparison with the surfactant-only systems, the surfactant–cellulose systems exhibit higher viscoelasticity of the continuous phase, as well as better shearing tolerance and self-recovery of emulsions. Ultimately, the microscopic oil displacement experiments demonstrate that the system can efficiently decrease the residual oil saturation after water flooding. These impressive performances make this blended system ideal for use in the chemical flooding process for EOR.

Wettability modification is one of the main mechanisms to increase oil recovery from low-permeability oil reservoirs. Nanofluids composed of nanoparticles can be used as modifiers to alter wettability from oil-wet to water-wet condition thus to promote hydrocarbon recovery. Biosurfactants, which are candidates to replace synthetic surfactants for industrial applications, have the potential to prepare nanofluids. In this study, nanofluids prepared by dispersing SiO2nanoparticles in rhamnolipid solution (hereby named bionanofluids) were considered potential wettability modifiers to apply to petroleum recovery from low-permeability sandstone reservoirs. Analyses via visual observation, optical absorbance measurement, ζ-potential determination, and particle size measurements demonstrated that the bionanofluids with 25 ppm rhamnolipids maintained an optimal stability. The effect of bionanofluids on wettability alteration was investigated through contact angle measurement and imbibition test. The results showed that bionanofluids could alter the wettability of oil-wet sandstone to strongly water-wet. The best performance was achieved with a nanoparticle concentration of 1000 ppm. Additionally, a micromodel test using rhamnolipid solution and bionanofluid was carried out to evaluate the synergistic effects of SiO2nanoparticles and rhamnolipid on displacing oil. Bionanofluid injection following biosurfactant flooding was shown to improve oil recovery, yielding an additional 5% production. These results reveal that the bionanofluid prepared with SiO2and rhamnolipids not only remained stable but also provided a potential way for enhanced oil recovery.

The formulation and mechanism of a hybrid ultralow interfacial tension spontaneous emulsification (SE) system consisting of alkyl polyglucoside surfactant and low-concentration alkali were investigated to enhance oil recovery for low-permeability reservoirs. Multiple-light scattering was used to characterize the stability and demulsification process of oil-in-water (O/W) emulsions. The emulsions were evaluated in terms of droplet size distribution, ζ potential, and three-phase rheological property. The average droplet size of the optimum SE O/W emulsion is about 0.2 μm, which is smaller than the average diameter of the low-permeability throats (0.2–4.0 μm). The coalescence and floatation of emulsion droplets are well-deferred. The oscillation–shear–oscillation rheological property could be further improved with the presence of the optimum system. This can be attributed to the synergistic effect of surfactants and alkali, which enables the formation of a more tight arrangement film of surfactants at the oil–water interface. Subsequently, diffusion of the surfactant from the interface to the bulk phase is inhibited by enhancing the interfacial viscosity. Moreover, the flooding results from the visual micromodel experiments demonstrate that the small residual oil droplets could be displaced easily in the porous media. The newly formulated SE system can be applied to enhance oil recovery for low-permeability reservoirs.

Polymer microspheres have been applied for petroleum reservoir enhanced oil recovery (EOR) in the past decade because they can overcome some drawbacks inherent in in situ polymer gel systems. A novel in situ surface decorated polymer microsphere technology was developed for chemical EOR in high-temperature reservoirs. The swelling performance of the conventional polymer microspheres at room temperature was systematically analyzed and verified by an environmental scanning electron microscope. Their swelling and degradation mechanisms at a high temperature (150 °C) were also examined. To improve the long-term thermal stability of the polymer microsphere, different concentrations of polyethylenimine (PEI) were used as an in situ surface decorating agent. The decorated microspheres remained stable at 150 °C for more than three months, and thermogravimetric analysis indicated that the in situ surface decorated polymer microspheres could remain stable at temperatures up to 310 °C. PEI-decorated 3D network structures on the surface of the microspheres prevented water molecules from entering inner structures, thereby inhibiting the polymer microspheres from swelling in aqueous solution under high temperatures. A sandpack flooding experiment showed how the in situ surface decorated polymer microspheres could effectively plug the porous media for water control and oil recovery improvement even after aging at 150 °C for two months. In situ surface polymer microspheres decorated with PEI can help petroleum engineers better apply this gel technology.

A combined profile modified system of starch graft copolymer (SGC) gel and N2foam was investigated to solve the problem of severe fluid channelling in multilayer heterogeneous reservoirs. The investigation was performed from three perspectives: formulas optimisation, blocking performance and oil displacement experiments to demonstrate synergetic blocking effect of the two plugging agents. The results show that this combined profile modified system could plug the higher permeability layers to force the subsequent injected water to mobilise the remaining oil in the lower permeability layer and create synergetic effect to improve oil recovery. [Received: March 8, 2016; Accepted: April 21, 2017]

The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N2injection in a multi-well fractured-cavity reservoir. In this study, the similar criterion of physical simulation was firstly discussed. In order to reveal the mechanism of remaining oil startup and production performance characteristic by continuous N2injection, a visualized two-dimensional fractured-cavity model and a three-dimensional pressure resistant model were designed and fabricated respectively based on the similar theory. And the 2D visualized physical experiments and 3D physical experiments were performed with the simulated oil and brine reservoir samples in Tahe oilfield. Four groups of experiments in 2D and 3D model were performed, each of which included bottom water depletion driving, water injection and N2injection. The 2D visualized experiments indicated the main mechanism of N2developing remaining oil was to occupy the high position and replace the attic oil due to gravitational differentiation. Furthermore, both the 2D and 3D experiments demonstrated that higher oil recovery factor could be achieved if N2was injected through high positional wells. The 3D physical model is closer to the real reservoir condition, so the production performance can reflect the real field production process. This paper confirmed the efficiency of continuous N2flooding in the light oil saturated fractured-cavity reservoir.

An in situterpolymer gel system formed by resorcinol–hexamethylenetetramine (HMTA) was developed and systematically evaluated for water management in extremely high-temperature reservoirs. Suitable gelation time and favorable gelation performance were obtained by adjusting terpolymer and/or cross-linker system concentrations. With the increase of the terpolymer, the resorcinol–HMTA concentration increased both the gelation time and gelation performance. The gel system was prepared by deionized water and maintained good thermostability in a high-salinity environment. Very low concentrations of NaCl, KCl, and CaCl2can delay gelation time. After the critical concentrations are reached, these inorganic ions will boost the cross-linking reaction; however, the presence of MgCl2shortens gelation time. The gel system in ampules was kept stable at 150 °C for 5 months, and the differential scanning calorimetry measurement indicated that the gel system could be used for water management at temperatures up to 240 °C. Uniformly distributed three-dimensional network microstructures and dendritic structures among the gel grid pores could further increase the network structure strength and firmly lock water within the gel even under extremely high temperatures. The use of the gelation mechanism of an in situterpolymer gel system formed by resorcinol–HMTA can help petroleum engineers control gelation time and performance.

Alkali is an important component for alkali/surfactant/polymer technology for enhanced oil recovery (EOR). The mechanism and advantages of traditional inorganic alkali for EOR was reviewed in this paper. The rheological and dynamic properties of the combination of alkali and polymer were analyzed. The results show that the polymer solution with ethanolamine has better shear viscosity and elastic properties at room temperature. Surfactant (Alfaterra 123-8S-90) with concentration of 0.15 wt % was added into each alkali–polymer (AP) solution. No significant change was observed in rheological properties of AP solutions with and without surfactant. Emulsification tests show that ethanolamine has better performance with oil. Injectivity tests were also conducted. The results indicated that the residual resistance factor (RRF) for an ethanolamine–polymer solution is always higher at each flow rate tested, in comparison to a NaOH-based AP solution, which is beneficial for oil recovery. The interfacial tension (IFT) tests results indicated that ethanolamine has better synergy with the surfactant. Polymer adsorption using both static and dynamic measurements was conducted. Polymer solution in an ethanolamine system has lower adsorption for both measurements. The pressure comparison during core flooding experiments shows that it has higher injection pressure in ethanolamine conditions, which result in good sweep efficiency. The ethanolamine–polymer flooding showed a significant increase in oil recovery (15.33%) over NaOH–polymer flooding. After the addition of surfactant, the total recovery improves by 14.8% for ethanolamine–polymer–surfactant flooding over its inorganic counterpart. The better performance indicates that ethanolamine can become a potential alkali and can replace NaOH for EOR.

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.

Gas flooding such as CO2flooding may be effectively applied to ultra-low permeability reservoirs, but gas channeling is inevitable due to low viscosity and high mobility of gas and formation heterogeneity. In order to mitigate or prevent gas channeling, ethylenediamine is chosen for permeability profile control. The reaction mechanism of ethylenediamine with CO2, injection performance, swept volume, and enhanced oil recovery were systematically evaluated. The reaction product of ethylenediamine and CO2was a white solid or a light yellow viscous liquid, which would mitigate or prevent gas channeling. Also, ethylenediamine could be easily injected into ultra-low permeability cores at high temperature with protective ethanol slugs. The core was swept by injection of 0.3 PV ethylenediamine. Oil displacement tests performed on heterogeneous models with closed fractures, oil recovery was significantly enhanced with injection of ethylenediamine. Experimental results showed that using ethylenediamine to plug high permeability layers would provide a new research idea for the gas injection in fractured, heterogeneous and ultra-low permeability reservoirs. This technology has the potential to be widely applied in oilfields.

The effect of active species present in crude oil on the interfacial tension (IFT) behavior of alkali/synthetic surfactants/crude oil systems was studied. The system consisted of heavy alkyl benzene sulfonate, sodium chloride, sodium hydrate and Daqing crude oil. Experimental results indicated that active species would diffuse from oil/aqueous interface to aqueous phase and finally an equilibrium could be reached in the system with increasing contact time. Moreover, the minimum IFT and equilibrium IFT values increased with increasing contact time and a linear relationship existed between dynamic IFT and t−1/2when IFT value approaching the minimum and after the minimum IFT was reached. This indicated that the dynamic IFT-time behavior was diffusion controlled. The oil and aqueous phases were analyzed by infrared (IR) spectroscopy. IR spectra of oil and aqueous phases illustrated that the content of active species in the oil phase decreased, but the content of active species in the aqueous phase increased after alkali reacted with crude oil. This indicated that the active species present in oil played an important role in reducing IFT.

The Fang-48 fault block oil reservoir is an extremely low permeability reservoir, and it is difficult to produce such a reservoir by waterflooding. Laboratory analysis of reservoir oil shows that the minimum miscibility pressure for CO2drive in Fang-48 fault block oil reservoir is 29 MPa, lower than the formation fracture pressure of 34 MPa, so the displacement mechanism is miscible drive. The threshold pressure gradient for gas injection is less than that for waterflooding, and the recovery by gas drive is higher than waterflooding. Furthermore, the threshold pressure gradient for carbon dioxide injection is smaller than that for hydrocarbon gas, and the oil recovery by carbon dioxide drive is higher than that by hydrocarbon gas displacement, so carbon dioxide drive is recommended for the development of the Fang-48 fault block oil reservoir.