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Alkaline-surfactant-polymer (ASP) flooding technology is used to maximize crude oil recovery. However, the extensive use of alkaline materials makes it difficult to treat the water used. Here, an improved multi-zone anaerobic baffled reactor (ABR) using FeSO.sub.4 as electron acceptor was employed to treat the wastewater from ASP flooding technology, and the effects on major pollutants (hydrolyzed polyacrylamide, petroleum substances, surfactants suspended solids) and associated parameters (chemical oxygen demand, viscosity) were evaluated. Gas chromatography-mass spectrometry (GC-MS) was used to follow the degradation and evolution of organic compounds while high-throughput DNA sequencing was used to determine the bacterial diversity in the ABR. The results obtained after 90 d of operation showed decreases in all parameters measured and the highest mean removal rates were obtained for petroleum substances (98.8%) and suspended solids (77.0%). Amounts of petroleum substances in the ABR effluent could meet the requirements of a national standard for oilfield reinjection water. GC-MS analysis showed that a wide range of chemicals (e.g. aromatic hydrocarbons, esters, alcohols, ketones) could be sequentially removed from the influent by each zone of ABR. The high-throughput DNA sequencing showed that the bacteria Micropruina, Saccharibacteria and Synergistaceae were involved in the degradation of pollutants in the anaerobic and anoxic reaction zones, while Rhodobacteraceae and Aliihoeflea were the main functional microorganisms in the aerobic reaction zones. The results demonstrated that the improved ABR reactor had the potential for the treatment of wastewater from ASP flooding technology.

Clean fracturing fluid has the characteristics of being environmentally friendly and causing little damage to reservoirs. Meanwhile, its backflow gel-breaking fluids (GBFs) can be reutilized as an oil displacement agent. This paper systematically evaluates the feasibility and EOR mechanism of a GBF based on a polymer surfactant as an oil displacement system for reutilization. A rotating interfacial tensiometer and contact angle measuring instrument were used to evaluate the performance of reducing the oil–water interfacial tension (IFT) and to change the rock wettability, respectively. Additionally, a homogeneous apparatus was used to prepare emulsions to evaluate GBF’s emulsifying properties. Finally, core flooding experiments were used to evaluate the EOR effect of GBFs, and the influence rules and main controlling effects of various properties on the EOR were clarified. As the concentration of GBFs increases, the IFT first decreases to the lowest of 0.37 mN/m at 0.20 wt% and then increases and the contact angle of the rock wall decreases from 129° and stabilizes at 42°. Meanwhile, the emulsion droplet size gradually decreases and stabilizes with increases in GBF concentration, and the smallest particle size occurs when the concentration is 0.12–0.15 wt%. The limited adsorption area of the oil–water interface and the long molecular chain are the main reasons that limit the continued IFT reduction and emulsion stability. The oil displacement experiment shows that the concentration of GBF solution to obtain the best EOR effect is 0.15 wt%. At this concentration, the IFT reduction and the emulsification performance are not optimal. This shows that the IFT reduction performance, reservoir wettability change performance, and emulsification performance jointly determine the EOR effect of GBFs. In contrast, the emulsifying performance of GBFs is the main controlling factor for the EOR. Finally, the optimal application concentration of GBFs is 0.15–0.20 wt%, and the optimal injection volume is 0.5 PV.

The aging of the existing reservoirs makes the hydrocarbon extraction shift toward newer reserves, and harsh conditioned carbonates, which possess high temperature and high salinity (HTHS). Conventional polymer-flooding fails in these HTHS carbonates, due to precipitation, viscosity loss, and polymer adsorption. Therefore, to counteract these challenges, novel polymer-based cEOR alternatives employ optimized polymers, polymer–surfactant, and alkali–surfactant–polymer solutions along with hybrid methods, which have shown a potential to target the residual or remaining oils in carbonates. Consequently, we investigate novel polymers, viz., ATBS, Scleroglucan, NVP-based polymers, and hydrophobic associative polymers, along with bio-polymers. These selected polymers have shown low shear sensitivity, low adsorption, and robust thermal/salinity tolerance. Additionally, adding an alkali-surfactant to polymer solution produces a synergy effect of improved mobility control, wettability alteration, and interfacial-tension reduction. Thus, enhancing the displacement and sweep efficiencies. Moreover, low-salinity water can precondition high-salinity reservoirs before polymer flooding (hybrid method), to decrease polymer adsorption and viscosity loss. Thus, this paper is a reference for novel polymers, and their hybrid techniques, to improve polymer-based cEOR field applications under HTHS conditions in carbonates. Additionally, the recommendations can assist in project designs with reasonable costs and minimal environmental impact. The implication of this work will aid in supplementing the oil and gas energy sector growth, making a positive contribution to the Middle Eastern economy.

Tight sandstone reservoirs usually experience a long flowback period after hydraulic fracturing, which significantly affects oil production. After fracturing, the well-soaking is commonly employed to control fracturing fluid flowback and enhance oil recovery, so that the oil in the reservoir matrix is replaced by fracturing fluid, which can improve the crude oil recovery and reduce the flowback of the fracturing fluid. In this paper, the gel breaking fluid of slick water fracturing fluid, guanidine gum fracturing fluid and cross-linked guanidine gum fracturing fluid are used as displacement working fluids to study the effect of gel breaking fluid on oil displacement in tight sandstone reservoirs. The results show that it is not the smaller the pore radius that the higher the displacement efficiency, but the oil displacement efficiency is higher for the equilibrium of capillary force and percolation resistance in a certain radius of pore throat. For tight sandstone reservoir, the oil displacement efficiency of small pore, middle pore and large pore is higher, the oil displacement efficiency of micro-pore is lower, and the oil in pore throat with radius less than 0.01 μm is difficult to be replaced. The lower the interfacial tension is, the lower the viscosity is, and the higher the oil displacement efficiency is. For tight sandstone reservoir, the displacement efficiency of crude oil can reach 13.11% −33.31%, the displacement of crude oil in the early stage is mainly displaced out of the middle and small pores, and then replaced out of the large pores and micro-pores of crude oil.

CO[sub.2] flooding technology for tight oil reservoirs not only effectively addresses the challenge of low recovery rates, but also facilitates geological CO[sub.2] sequestration, thereby achieving the dual objective of enhanced CO[sub.2] utilization and secure storage. However, in the development of continental sedimentary tight oil reservoirs, the high content of heavy hydrocarbons in crude oil leads to an elevated minimum miscibility pressure (MMP) between crude oil and CO[sub.2] , thereby limiting the process to non-miscible flooding. Conventional physical and chemical methods, although effective in reducing MMP, are often associated with high costs, environmental concerns, and limited efficacy. To address these challenges, we propose a novel approach utilizing petroleum hydrocarbon-degrading bacteria (PHDB) to biodegrade heavy hydrocarbons in crude oil. This method alters the composition of crude oil, thereby lowering the MMP during CO[sub.2] flooding, facilitating the transition from non-miscible to miscible flooding, and enhancing oil recovery. Results demonstrated that, after 7 days of cultivation, the selected PHDB achieved a degradation efficiency of 56.4% in crude oil, significantly reducing the heavy hydrocarbon content. The relative content of light-saturated hydrocarbons increased by 15.6%, and the carbon atom molar percentage in crude oil decreased from C8 to C6. Following the biodegradation process, the MMP of the lightened crude oil was reduced by 20.9%. Core flood experiments indicated that CO[sub.2] flooding enhanced by PHDB improved oil recovery by 17.7% compared to conventional CO[sub.2] flooding. This research provides a novel technical approach for the green and cost-effective development of tight oil reservoirs with CO[sub.2] immiscible flooding.

To achieve the efficient utilization of low-permeability tight sand and gravel reservoirs with strong heterogeneity in the Mahu oil area of Xinjiang, CO[sub.2] injection is used to improve oil recovery. The sweep pattern of the injected gas is closely related to the development of reservoir pores and throats. Firstly, a three-dimensional model of the average pore-throat radius was established based on complete two-dimensional nuclear magnetic resonance scanning data of the target layer’s full-diameter core in the Wuerhe Formation. Subsequently, an online NMR injection CO[sub.2] continuous oil displacement experiment was conducted using tight conglomerate rock cores to clarify the rules of CO[sub.2] oil displacement in each pore-throat interval. Finally, the three-dimensional pore-throat model was combined with microscopic utilization patterns to quantitatively characterize the reservoir utilization rate of the CO[sub.2] displacement oil and guide on-site dynamic analysis. The research results indicate that the reservoir space of the Wuerhe Formation is mainly composed of residual intergranular pores, accounting for 40.9% of the pores, followed by intragranular dissolution pores and shrinkage pores. The proportion of pore-throat coordination numbers less than 1 is relatively high, reaching 86.3%. The average pore-throat radius calculation model, established using online NMR data from the continuous coring of full-diameter cores, elucidates the characteristics of the average pore-throat radius in the Wuerhe Formation reservoir. Based on gas displacement experiments that explored the pore-throat behavior at the microscale, the calibrated CO[sub.2] injection oil recovery rate was determined to be 43.9%, and the proportion of reserves utilized within the main range during CO[sub.2] displacement amounted to 60.77%. The injection pressure is negatively correlated with the maximum pore-throat radius of the gas injection well group, and negatively correlated with the proportion of the 0.9~2 μm distribution of large pore throats in each gas injection well group.

The Sichuan Basin’s Liangshan Formation shale is rich in oil and gas resources, yet the recovery rate of shale oil reservoirs typically falls below 10%. Currently, gas injection huff-n-puff (H-n-P) is considered one of the most promising methods for improving shale oil recovery. This study numerically investigates the application of the CO[sub.2] huff-n-puff process in enhancing oil recovery in shale volatile oil reservoirs. Using an actual geological model and fluid properties of shale oil reservoirs in the Sichuan Basin, the CO[sub.2] huff-n-puff process was simulated. The model takes into account the molecular diffusion of CO[sub.2] , adsorption, stress sensitivity effects, and nanopore confinement. After history matching, through sensitivity analysis, the optimal injection rate of 400 tons/day, soaking time of 30 days, and three cycles of huff-n-puff were determined to be the most effective. The simulation results show that, compared with other gases, CO[sub.2] has significant potential in improving the recovery rate and overall efficiency of shale oil reservoirs. This study is of great significance and can provide valuable references for the actual work of CO[sub.2] huff-n-puff processes in shale volatile oil reservoirs of the Sichuan Basin.

CO[sub.2] huff-n-puff is regarded as an effective method to improve the recovery of low permeability and tight oil reservoirs. To understand the impact of CO[sub.2] huff-n-puff on crude oil mobilization in tight reservoirs with different fracture scales, this study conducted CO[sub.2] huff-n-puff nuclear magnetic resonance (NMR) and microscopic visualization experiments, focusing on how varying fracture apertures and densities affect the efficiency of the CO[sub.2] huff-n-puff. The results show that in scenarios with a single fracture, larger fracture apertures significantly boost oil mobilization within the fracture and the surrounding matrix. For instance, increasing the aperture from 20 μm to 70 μm improved the recovery factor by 9.20%. In environments with multiple fractures, greater fracture density enhances reservoir connectivity, and increases the CO[sub.2] sweep area, and the complex fracture model shows a 4.26% increase in matrix utilization compared to the simple fracture model. Notably, the improvement in recovery due to multi-scale fractures is most significant during the first two huff-and-puff cycles, with diminishing returns in subsequent cycles. Overall, increasing both fracture size and density effectively enhances crude oil mobilization in tight reservoirs. These findings provide valuable insights into improving the recovery efficiency of CO[sub.2] huff-and-puff techniques in tight oil reservoirs.

Shale oil, a critical unconventional energy resource, has received substantial attention in recent years. However, systematic research on developing shale oil using mixed gases remains limited, and the effects of various gas compositions on crude oil and rock properties, along with their potential for enhanced oil recovery, are not yet fully understood. This study utilizes PVT analysis, SEM, and core flooding tests with various gas mixtures to elucidate the interaction mechanisms among crude oil, gas, and rock, as well as the recovery efficiency of different gas types. The results indicate that increasing the mole fraction of CH[sub.4] substantially raises the oil saturation pressure, up to 1.5 times its initial value. Pure CO[sub.2] , by contrast, exhibits the lowest saturation pressure, rendering it suitable for long-term pressurization strategies. CO[sub.2] shows exceptional efficacy in reducing interfacial tension, though the viscosity reduction effects of different gases exhibit minimal variation. Furthermore, CO[sub.2] markedly modifies the pore structure of shale through dissolution, increasing porosity by 2% and enhancing permeability by 61.63%. In both matrix and fractured cores, the recovery rates achieved with mixed gases were 36.9% and 58.6%, respectively, demonstrating improved production compared to single-component gases. This research offers a theoretical foundation and novel insights into shale oil development.

As the energy demand is escalating tremendously and crude oil being the primary energy source for at least the next two decades, the production of crude oil should be enhanced to meet the global energy needs. This can be achieved by either exploration of new oil fields for crude oil extraction or employing enhanced oil recovery (EOR) technology to recover the residual oil from existing marginal oil fields. The former method requires more capital investment and time; therefore, this review focuses on the latter. In general, the abandoned oil fields still have 50% of crude left which is unrecovered due to lack of technology. Hence, EOR came into existence after the conventional methods of recovery (primary and secondary recovery) were found to be inefficient and less economical. Nineteen percent of the EOR projects are based upon cEOR methods worldwide, of which more than 80% of projects use economically feasible polymer flooding process for oil recovery. Both synthetic and naturally derived polymers have been used widely for this purpose; however, many recent studies have shown the lower stability of synthetic polymers under extreme reservoir conditions of high salinity and temperature. Additionally, naturally derived polymers face microbial degradation as the major limitation. Therefore, a number of novel polymers are currently studied for their suitability as an efficient EOR polymer. Latest findings have also revealed that biopolymers play an important role in wettability alteration, pore evolution by bioplugging, and reducing fingering effect. Injection of biopolymers can also lead to the selective plugging of thief zones which redirects water flood to the inaccessible oil pores. Therefore, the current study focuses on such principle and mechanism of polymer flooding along with the reservoir and field characteristics which affects the polymer flooding. It also discusses the scope of biopolymer along with the screening criteria for use of novel polymers and strategies to overcome the problems during polymer flooding.Key points• Discussion of macroscopic and microscopic mechanisms of polymer flooding.• Screening criteria of polymers prior to flooding are essential.• Biopolymers are eco-friendly and are applicable for a wide range of reservoir conditions.