The effects of the number of imidazoline ring and the length of alkyl group chain of imidazoline derivatives were investigated using quantum chemical calculation, molecular dynamics simulation and experimental techniques. Three corrosion inhibitors including symmetrical lauric acid imidazoline (SAI), tetracyclic lauric acid imidazoline (LAI), and symmetric stearic acid imidazoline (SPI) were synthesized and their inhibition performance was evaluated using weight loss measurement, electrochemical techniques and surface characterization. The results show that SAI and LAI with the same length of alkyl group chain, LAI with more imidazoline rings could supply a better inhibition performance since the increase of active sites. The increase of active sites attached to the metal surface may also change the distribution of corrosion inhibitor, which could limit inhibition performance improvement. While, SAI and SPI with the same number of imidazoline rings, SPI with longer alkyl group chain shows a better inhibition efficiency due to the better hydrophobic performance of alkyl groups. Among the three inhibitors, SPI shows the best inhibition performance, indicating that the alkyl group chain length affects the inhibition performance more obvious than the number of the imidazoline rings.

This work numerically investigates surfactant effects on spontaneous water imbibition in oil-wet carbonates. An open boundary core-scale imbibition model with 9 × 9 × 10 gridblocks was used in UTCHEM to simulate carbonate core plug exposure to a vast water body. The simulation models were developed based on surfactant-assisted imbibition tests that were conducted in secondary and tertiary oil production modes using Amott cells at 75°C. Capillary and gravity forces were captured by history matching the experiments. Through history matching, the inputs for surfactant adsorption and diffusion, capillary pressure and relative permeability were calibrated. In tertiary mode, the surfactants-assisted imbibition process presents the performance in mixed-wet state rather than oil-wet state, which is governed by wettability alteration. A simulation model for surfactant-assisted imbibition in secondary mode was used to investigate the effects of various factors including interfacial tension (IFT) reduction, wettability alteration, adsorption, volume of surrounding water and capillary force. The simulation results suggest that surfactant-assisted water imbibition in secondary mode is gravity dominant, which is facilitated by both IFT reduction and wettability alteration caused by addition of proper surfactants. Different from water imbibition in water-wet core, it presents vertically dominant oil flow with a hemispherical oil-rich area and uneven remaining oil saturation. It is obvious that sufficient surfactant supply in vast water is required to make effective imbibition, in consideration of surfactant consumption and changes in concentration gradients. This core-scale modeling provides insights of surfactant-assisted imbibition in initially oil-wet carbonates and helps scale up the application in a cost-effective way.

A hybrid enhanced oil recovery (EOR) method by combining low salinity water (LSW) and low salinity surfactant (LSS) flooding techniques was designed. Different experiments were done to screen the Caspian seawater (SW) with altered ionic composition and surfactant, for the optimized performance in Kazakhstani carbonate oil fields. Changing to a more water-wet state and creating the middle phase were studied as the main criteria to select the best-engineered brine and anionic surfactant. The largest alteration towards the water-wet condition was recorded at 10 times dilution of the SW with 3-and 6-times spiked calcium and sulfate ions, respectively (10xSW-6SO4, Mg, 3Ca). This combination of anionic surfactants with carbonate formations is considered as a new approach in hybrid EOR methods. Among the anionic surfactants screened, Soloterra-113H (alkyl benzenesulfonic acid) showed the best solubilization ratio, aqueous stability and Winsor type 3 microemulsions. The wettability alteration by the combination of optimized brine and screened surfactant was greater compared to the standalone LSW, which was confirmed by the 10° difference in contact angle measurement. The microemulsion phase constituted nearly 40% of the total height of the oil/brine column by the hybrid method. The recovery factor after injecting formation water was 52%, and it increased to 61% after optimized LSW injection. After switching to the engineered brine/surfactant, the recovery factor reached 70%, which proves the effectiveness of the hybrid method. The proposed combined method works better than either standalone EOR method due to the higher alteration in capillary number by changing wettability and reducing IFT, which leads to higher oil recovery.

Increasing the number of depleted reservoirs and global demand for energy have left us with low alternative but to use new ways to extract more hydrocarbon. Amongst different material used for tertiary oil recovery, surfactant injection has proved very promising solutions, such as interfacial tension reduction and wettability alteration. Without any harm to the environment and meanwhile being economically feasible, natural surfactants have been attracted researchers in recent years. Cedr extraction which is produced from Zizyphus Spina Christi leaves has shown some beneficial characteristics like IFT reduction and wettability alteration. However, the amount of IFT reduction is not considerable, so we decided to augment its effectiveness by adding two different nanoparticles. In this investigation, three concentrations (0.01, 0.05 and 0.1 wt%) of both graphene oxide (GO) nanosheet and GO/TiO₂ nanocomposite was added to Cedr extraction solution to study their potential on IFT reduction and improving the ultimate oil recovery. The concentration of 0.05 wt percent showed the lowest IFT in both solutions. At this concentration, the IFT of GO/TiO₂-augmented solution and GO-augmented solution were measured of 10.5 and 12.3 mN/m, respectively. While the bare Cedr solution showed 23.8 mN/m at its critical micelle concentration. The coreflooding tests were also performed at the aforementioned concentrations. Final oil recovery reached to 65% of original oil volume in GO/TiO₂-augmented solution, compared to 56% in GO-augmented solution case and 40% in bare Cedr solution case. Scanning Electron Microscopy images were also taken from the rock samples exposed to nanofluids to investigate any severe harm to the permeability. Images showed low tendency of both particles to adsorb on rock surface and plug large pores.

Inspired by the viscoelastic displacement theory, a product called preformed particle gel (PPG) is developed as conformance control agent to enhance oil recovery and control excess water production. The migration law of PPG suspension in porous media is related to its deep profile control and displacement capability. Laboratory experiments indicate that PPG suspension has good viscosity increasing, and the apparent viscosity decreases with the increase of shear rate. PPG suspension is mainly elastic, and its network structure makes it have certain shear stability. PPG particles realize migration in porous media in the way of “accumulation and blockage→pressure increase→deformation and migration”. When the ratio of the PPG particle size to the pore throat diameter δ ranges from 35.52 to 53.38, the particles can match through the porous medium. When the permeability difference of the parallel model is 5, PPG suspension has the highest profile improvement rate, 69.10%. PPG suspension can adjust the planar heterogeneity, and increase the oil recovery rate by 20.75%. The PPG suspension can effectively start “cluster"、 “film” and “blind end residual oil”, and has a high oil washing efficiency. The core NMR T₂ spectrum shows that PPG suspension mainly reduces oil saturation in mesopores and macropores. After PPG flooding, the EOR capacity of small pores is the highest, 39.11%.

Initial wettability of rock surfaces plays a crucial role in displacement efficiency during core flooding experiments. In this study, linear alkylbenzene sulfonic acid (LABSA) and silica nanoparticles (NPs) were utilized as enhanced oil recovery (EOR) agents to improve oil recovery from carbonate rock samples. Prior to the core flooding experiments, effects of the presence of LABSA and SiO₂ NPs on oil-water interfacial tension (IFT), wettability alteration, and surfactant adsorption on the rock surfaces were evaluated. The results of IFT/contact angle measurements showed that by adding 0.03 wt% LABSA, the IFT, and contact angle reduced from the initial values of 36.9 mN/m and 115.6° ± 0.2° to 8.3 mN/m and 100.3° ± 0.4°, respectively. Furthermore, incorporating SiO₂ NPs (0.1 wt%) into the system causes a further decrease in IFT value (dropped to 2.2 mN/m), along with a substantial reduction in contact angle (final contact angle after 6 h soaking into the solution was measured as 64.8° ± 0.3°). In addition, surfactant loss due to the adsorption on the rock surfaces decreased up to 35% in the presence of SiO₂ NPs (0.1 wt%). Moreover, various core flooding scenarios in carbonate plugs with different initial wettability conditions were conducted, and the performance of the EOR agents in enhancing oil recovery from oil-wet and water-wet core samples in the secondary and tertiary mode of flooding was evaluated. The outcomes revealed that the injection of a combination of chemicals, containing LABSA (0.03 wt %) and SiO₂ (0.1 wt%) in the secondary mode leads to the highest ultimate oil recovery from sister carbonate core samples.

Drilling muds play an important role in drilling and production operations so that the degree of success in such operations is determined by the proper design of these fluids. To optimize drilling operations and avoid excessive expenditure, it is essential to prepare a drilling mud that is both cheap and efficient. Fluid additives are typically used in drilling systems to improve these fluids' capabilities in terms of hole cleaning capacity, filtration control, viscosity, yield point, heat transfer, etc. However, environmental concerns, cost of production, and availability are always considered challenging factors. This study introduces an eco-friendly herbal fiber in powder and regular forms as a potential alternative to other chemical additives. To do so, alyssum homolocarpum seed mucilage was added with different concentrations to the water-based drilling muds, and its rheological behavior, filtration control, and the induced formation damage were examined and the optimum concentration was introduced. The results of this study revealed the advantages of the drilling muds formulated with alyssum in terms of filtration control, rheology, formation damage, and greenness.

Foam diversion acidizing can effectively solve the problem of acid distribution with severe heterogeneity between and within layers. Based on the foam diversion principle, the gas trap theory, and volume conservation principle, the foam slug diversion acidizing model was established and solved considering the change of bottomhole temperature and deviation factor of foam. The simulation results show that the change of temperature has a great influence on the diversion effect at the initial stage of injection, but a small influence at the middle and late stage. The effect of temperature on the highly permeable layer is greater than that of temperature on the low permeability layer. The deviation factor of foam is mainly controlled by temperature at the initial stage, and by pressure at the middle and late stage, and the whole process shows a downward trend, which has little influence on the diversion effect. The quasi-skin factor of gas trap is the most important parameter that influences the effect of foam diversion. The water saturation of the low permeability layer rises faster than that of the high permeability layer, and the effect of diversion is obvious. The research results have a strong guiding significance for foam diversion acidizing.

Worm-like micelles are of special interest among the many forms of surfactant aggregates because of their usefulness in research and technology. Micelles are elongated, flexible aggregates formed by amphiphilic molecules spontaneously self-organizing in liquids. The nature of the surfactant determines its unique shape, which may be altered by mixing it with other substances or changing physicochemical variables like as temperature, pH, or salinity. The rheology of viscoelastic fluid systems is currently being modified using nanoparticles. This method, which was just introduced about 10 years ago, has shown to be highly promising, producing significant improvements in rheological properties, particularly at reservoir temperatures. The goal of this research is to investigate and assess the rheology of an aqueous cationic surfactant solution based on graphene oxide nanoparticles. The thermodynamics, structure and rheology of nanoparticle-based cationic surfactant solutions were investigated experimentally. According to structural and thermodynamic investigations in surfactant-nanoparticle mixtures, micelle-nanoparticle interactions arise as physical crosslinks between micelles. The existence of these interactions is shown to generate considerable viscosity and viscoelasticity in wormlike micelles, even when the fluid is Newtonian in the absence of nanoparticles. The viscosity, shear modulus and relaxation time all increase as particle concentration increases. Adding nanoparticles generates a network of micellar entanglements as a result of that. Our results demonstrate that adding nanoparticles to surfactant solutions provides for a one-of-a-kind method of altering fluid rheology under a range of circumstances.

Wellbore instability in oil and gas industry well drillings is a significant challenge that is linked to shale swelling when shale interacts with free water molecules in the water-based drilling fluid. Strategic design of environmentally benign, biodegradable, and effective shale hydration inhibitors is a prominent objective of contemporary exploration in well-drilling fluids as a replacement for the common KCl which is detrimental to aquatic lives. This work reports the synthesis and potential of novel green acrylic polymer-amyl ester activated carbon (-C) nanocomposite to hinder shale hydration in formations during drilling. Both less hydrophobic acrylic acid-acrylamide-activated carbon-amyl ester (AA-AAm-C-Amyl) and more hydrophobic acrylic acid-acrylamide-octadecene-activated carbon-amyl ester (AA-AAm-OD-C-Amyl) composites were synthesized, characterized, and tested with standard methods as a cleaner fluid additive for shale swelling inhibition, and their results compared with that of KCl. The polymer matrixes displayed remarkable thermal stability. Results also indicate that AA-AAm-C-Amyl and AA-AAm-OD-C-Amyl composites could stabilize wellbore effectively with 95.2% and 93.7% anti-swelling ratio, and shale recovery capacity of 97% and 95.2% respectively. The surface evaluation of the composite fluid-treated bentonite revealed that the mechanism of inhibition could be based on the collaborative action of nanopore plugging of carbon core and strong adsorption of the polymer component of the materials on clay surfaces via encapsulation and hydrogen bonding to form an impressive filter cake which could actively prevent water invasion into formation. Hence, AA-AAm-C-Amyl and AA-AAm-OD-C-Amyl composites could be a sustainable substitute for the conventional KCl as a shale inhibitor for well-drilling.

China is rich in shale gas resources, however, wellbores in shale gas reservoirs are frequently unstable. This has a serious impact on the shale gas drilling cycle. Polyamine, a common additive in water-based shale drilling fluids, can effectively inhibit shale hydration. However, there is a lack of quantitative research on the effect of polyamine inhibitors on the microstructure and macromechanical properties of shale. Therefore, this study investigated those issues via a systematic hydration experiment carried out on shale from the Longmaxi Formation. The results show that microfractures are created and expand during shale hydration, that they also connect to form a complex microfracture network, and that 3% polyamine inhibitors (polyamine solution with volume fraction of 3%) can effectively inhibit their evolution. The ultrasonic velocities and UCS of the Longmaxi shale are significantly anisotropic; the former first increases and then decreases with the laminae angle, reaching its maximum when the laminae angle is 30°. The UCS of the shale is highest and lowest, respectively, when the laminae angles are 0° or 90° and 30°. In general, these UCS appear as a “U" pattern, high on two sides with a dip in the center. Polyamines can effectively inhibit both the expansion of shale and the reduction of P-wave and S-wave velocities, the UCS, and elastic modulus. The UCS of a shale sample was reduced by 28%-40% after immersion for 96 h in water, compared to 2%-20% after immersion in a 3% polyamine inhibitor for the same amount of time. The inhibiting effect of the polyamine was remarkable.

Application of CO₂ gas in foam enhanced oil recovery (EOR) processes has emerged as a win-win strategy for achieving higher oil recovery factor and reducing greenhouse gas emission, which can significantly help the protection of the ozone layer from depletion. However, lower stability of CO₂-foam, as compared to the N₂-and CH₄-foams, has tempted us to examine combinations of CO₂ with these gases to not only improve the stability of the produced foam but also have CO₂ as the gaseous phase of the foam. In this study, we investigated the effect of different gases and the mixture thereof on the performance of foams in EOR while the aqueous phase of foams is a constant mixture of Cocamidopropyl betaine surfactant (0.03 wt%) and silica nanoparticle (0.1 wt%). To this end, seven different gases, including N₂, CO₂, CH₄, 80% N₂ + 20% CO₂, 80% CH₄ + 20% CO₂, 50% CH₄ + 50% CO₂, 50% N₂ + 50% CO₂ were used as the gases phase for foam generation and the performance of the produced foams were examined through the following experiments: bulk foam stability tests, apparent foam viscosity measurements and core flooding tests. The results of foam stability tests showed that half-life time for the CO₂-, CH₄-and N₂-foams are 13.5, 17.0 and 44.0 min, respectively. Also, as revealed from apparent viscosity measurements, the N₂-and 80% N₂+20% CO₂ foams have higher apparent foam viscosity values followed by 50% N₂+50% CO₂ foam. Furthermore, we showed that a combination of 80% N₂ + 20% CO₂ as the gaseous phase for foam generation could not only improve CO₂-foam stability, as compared to other foams, but also can substantially increase ultimate oil recovery (56.6 %OOIP), even more than that for N₂ foam (48.6 %OOIP), obtained from core flooding experiments.

Heavy crude oil (HCO) production, processing, and transportation forms several practical challenges to the oil and gas industry, due to its higher viscosity. Understanding the shear rheology of this HCO is highly important to tackle production and flow assurance. The environmental and economic viability of the conventional methods(thermal or dilution with organic solvents), force the industry to find an alternative. The present study was constructed to investigate the effect of eco-friendly ionic liquids (ILs) on the HCO's rheology, at high temperature and high pressure. Eight different alkyl ammonium ILs were screened for HCO's shear rheology at the temperatures of 25-100 °C and for pressures 0.1-10 MPa. The addition of ILs reduced the HCO's viscosity substantially from 25 to 33% from their original HCO viscosity. Also, it aids to reduce the yield stress to about 15-20% at all the studied experimental conditions. Furthermore, the viscoelastic property of the HCO was studied for both strain-sweep and frequency-sweep and noticed the ILs helps to increase HCO's loss modulus (G″) by reducing storage modulus (G′), it leads to the reduction of the crossover point around 25-32% than the standard HCO. Mean the ILs addition with HCO converts its solid-like nature into liquid-like material. Besides, the effect ILs chain length was also studied and found the ILs which has lengthier chain length shows better efficiency on the flow-ability. Finally, the microscopic investigation of the HCO sample was analyzed with and without ILs and witnessed that these ILs help to fragment the flocculated HCO into smaller fractions. These findings indicate that the ILs could be considered as the better alternative for efficient oil production, processing, and transportation.

Gum ghatti (anogeissus latifolia) is being widely used as an emulsifier, thickener, stabilizer in food, pharmaceutical, and allied industries due to its shelf life, tolerance of heat, and pH stability. Considering the oil & gas industry application, it is ideal for a hydraulic fracturing fluid additive as a direct replacement for guar gum. Basically, unlike guar gum, it contains less residual hull and it is suitable for low permeability unconventional reservoir; mainly shale gas reservoir, where permeability counts trivial in amount. The polymer of ghatti aid exceptional rheological properties and help to produce higher molecular weight polymer; which has excellent proppant carrying capacity and fracture propagation. In this paper, the experimental study has been carried out in two different phases. This was achieved through optimization and characterization of hydraulic fracturing fluid which was embedded with gum matrices. In Phase-I, the study was carried out by using response surface methodology (RSM). Wherein, the relation between several explanatory and response variables have been measured. In Phase-II, the characterization was done by using a scanning electron microscope (SEM), differential scanning calorimeter (DSC), thermo-gravimetric analysis (TGA) and also, Fourier-transform infrared spectroscopy (FT-IR). This experimental study will potentially benefit for development of a new hydraulic fracturing fluid. Where gum ghatti observed as a satisfactory alternative agent for guar gum.

In this paper, the bubble-point pressures and pseudo bubble-point pressures of various heavy crude oil−solvent systems were measured and studied by conducting the constant-composition-expansion (CCE) tests, during which the test pressure was depleted in a stepwise manner. A total of fourteen CCE tests were performed for five heavy crude oil−CO₂ systems, four heavy crude oil−CH₄ systems, and five heavy crude oil−C₃H₈ systems, respectively. All the CCE tests were conducted by using a pressure−volume−temperature (PVT) system. It was found that for most heavy crude oil−solvent systems with relatively low solvent concentrations, the measured PVT cell pressure vs. molar volume (P_cell−ν_mix) data in the CCE tests had three distinct regions, which were one-liquid phase region (Regions I), foamy-oil region (Region II) and two-phase region (Region III). Accordingly, the PVT cell pressure at the intersection point of Regions I and II was referred to as the measured bubble-point pressure, whereas the PVT cell pressure at the intersection point of Regions II and III was termed as the measured pseudo bubble-point pressure. For some heavy crude oil−solvent systems with high solvent concentrations, however, the measured P_cell−ν_mix data may have two regions only. In this special case, the PVT cell pressure at the intersection point of the two regions was considered as the measured bubble-point pressure and no pseudo bubble-point pressure could be obtained. It was also found that the heavy crude oil−CH₄ system had not only the highest bubble-point pressure and pseudo bubble-point pressure but also the largest difference between the bubble-point pressure and pseudo bubble-point pressure, in comparison with the heavy crude oil−CO₂ system and the heavy crude oil−C₃H₈ system at the same solvent concentration. These facts indicate that CH₄ not only is the most volatile solvent but also can remain as dispersed gas bubbles to induce the most stable foamy oil in the largest pressure range after it is nucleated from a live heavy oil.