Search Results (52)

To address the problems of complex composition, significant property variations, and difficult and costly harmless treatment of oil-contaminated sludge in oil and gas field development, its good compatibility with the formation is leveraged to formulate it with oilfield water into an oil–water profile control agent. This reduces the cost of harmless treatment and enables resource utilization of hazardous waste. The properties of oil-contaminated sludge were evaluated experimentally. Suspending agents and stabilizers were selected according to the oil–water profile control agent preparation process, the corresponding agents were prepared, and the system was experimentally tested. The experimental results show that the suspending agent carboxymethyl cellulose (CMC) and partially hydrolyzed polyacrylamide (HPAM), and the dispersant Dodecyl dimethyl betaine (BS-12) are used to prepare oil–water profile control agent based on the selected sulfonated mud oily sludge and ground system oily sludge. The optimal formulation of profile control agent is as follows: (1) 50% ground system oily sludge +50% oilfield produced water + 0.2% CMC + 1.0% BS-12; (2) 50% sulfonated mud system oily sludge +50% oilfield produced water + 0.1% HPAM + 1.0% BS-12. The preparation of a profile control agent from oily sludge is a viable low-cost resource treatment strategy for oily sludge, which is of great significance for the environmentally friendly treatment of oil and gas field development. Full article

Continental high water-cut reservoirs commonly exhibit strong heterogeneity, high viscosity, and insufficient reservoir drive, which has motivated the deployment of polymer-based composite chemical flooding, such as surfactant–polymer (SP) and alkali–surfactant–polymer (ASP) processes. However, conventional experimental techniques have limited ability to resolve intermolecular forces, and the coupled mechanism linking “formulation composition” to “microstructural evolution” remains insufficiently defined, constraining improvements in field performance. Here, scanning electron microscopy (SEM), backscattered electron (BSE) imaging, and molecular dynamics (MD) simulations are integrated to systematically investigate microstructural features of polymer composite systems and the governing mechanisms, including hydrogen bonding and electrostatic interactions. The results show that increasing the concentration of partially hydrolyzed polyacrylamide (HPAM) promotes hydrogen bond formation and the development of network structures; a moderate amount of surfactant strengthens interactions with polymer chains, whereas overdosing loosens the structure via electrostatic repulsion; the introduction of alkali reduces polymer connectivity, shifting the system toward an ion-dominated dispersed morphology. These insights provide a mechanistic basis for elucidating the behavior of polymer composite formulations, support enhanced chemical flooding performance, and ultimately advance the economic and efficient development of oil and gas resources. Full article

HPAM-Cr³⁺ (partially hydrolyzed polyacrylamide-chromium ion) gels are widely used in enhancing oil recovery (EOR) due to their advantages of low cost, controllability, and high strength. The propagation distance of gels within the reservoir significantly negatively impacts their gelation performance. However, the extent of this influence remains unclear, hindering precise optimization for field applications. This study first established a gelation performance characterization method based on visual inspection, rheological parameters, and long-term stability, accurately classifying gels into five types: stable strong gel (SSG), stable weak gel (SWG), colloidal dispersion gel (CDG), unstable gel (USG), and over-crosslinked gel (OCG). Subsequently, cross-experiments were conducted using varying concentrations of HPAM and Cr³⁺. Based on the contour map of visual appearance, storage modulus (G′), and water loss rate (R_w) of the gels, distribution maps of gel morphology versus concentration were constructed. The gel performance was found to depend on the HPAM concentration and the crosslinking ratio (molar ratio of HPAM carboxyl groups to Cr³⁺ ions). No gel formation occurred when the HPAM concentration was below 800 mg/L, while concentrations above 2500 mg/L effectively inhibited over-crosslinking. The crosslinking ratio range for forming SSG was 5.56 to 18.68, with an optimal value of 9.27. Furthermore, the effect of propagation distance on gelation performance was investigated through 60 m sand-packed flow experiments. Results indicated that the minimum value of the crosslinking ratio was 2.632, the stable SSG formed when the propagation distance was less than 21 m, SWG formed within the 21–34 m range, and no intact gel formed beyond 34 m. It means that only the first 35% of the designed distance formed effective SSG for plugging. Finally, an optimization method for gel dosage design was established based on the findings. This method determines the optimal gel dosage for achieving effective plugging by calculating the volume of crosslinking system passing through the target fluid diversion interface and referencing the gel morphology distribution maps. These findings provide a straightforward and effective approach for the precise design of in-depth profile control agents. Full article

Carbon dioxide (CO₂) has been widely applied in gas flooding for reservoir development due to its remarkable oil recovery potential. However, because its viscosity is lower than that of water and most crude oils, severe channeling often occurs during the flooding process, resulting in a significant reduction in the sweep efficiency. To address this issue, foam flooding has attracted considerable attention as an effective method for controlling CO₂ mobility. In this study, a compound foam system was developed with alpha-olefin sulfonate (AOS) as the primary foaming agent, alcohol ethoxylate (AEO) and cetyltrimethylammonium bromide (CTAB) as co-surfactants, and partially hydrolyzed polyacrylamide (HPAM) as the stabilizer. The optimal system was screened through evaluations of comprehensive foam index, salt tolerance, oil resistance, and shear resistance. Results indicate that the AOS+AEO formulation exhibits superior foaming ability, salt tolerance, and foam stability compared with the AOS+CTAB system, with the best performance achieved at a mass ratio of 2:1 (AOS:AEO), balancing both adaptability and economic feasibility. A heterogeneous reservoir model was constructed using parallel core flooding to investigate the displacement performance and blocking capability of the system. Nuclear magnetic resonance (NMR) imaging was employed to monitor in situ oil phase migration and clarify the recovery mechanisms. Experimental results show that the compound foam system demonstrates excellent conformance control performance, achieving a blocking efficiency of 84.5% and improving the overall oil recovery by 4.6%. NMR imaging further reveals that the system effectively mobilizes low-permeability zones, with T₂ spectrum analysis indicating a 4.5% incremental recovery in low-permeability layers. Moreover, in reservoirs with larger permeability ratio, the system exhibits enhanced blocking efficiency (up to 86.5%), though the incremental recovery is not strictly proportional to the blocking effect. Compared with previous AOS-based CO₂ foam studies that primarily relied on pressure drop and effluent analyses, this work introduces NMR imaging and T₂ spectrum diagnostics to directly visualize pore-scale fluid redistribution and quantify sweep efficiency within heterogeneous cores. The NMR data provide mechanistic evidence that the enhanced recovery originates from selective foam propagation and the mobilization of residual oil in low-permeability channels, rather than merely from increased flow resistance. This integration of advanced pore-scale imaging with macroscopic displacement analysis represents a mechanistic advancement over conventional CO₂ foam evaluations, offering new insights into the conformance control behavior of AOS-based foam systems in heterogeneous reservoirs. Full article

This study explores the potential of biopolymers as sustainable alternatives to synthetic polymers in enhanced oil recovery (EOR), aiming to reduce reliance on partially hydrolyzed polyacrylamides (HPAM). Mucilage extracted from Opuntia ficus-indica cladodes was investigated individually and in combination with HPAM in an 80/20 blend. The objective was to evaluate the physicochemical and rheological properties of these formulations, and their efficiency in improving oil recovery under realistic reservoir conditions. The materials were characterized using thermogravimetric analysis (TGA), X-ray diffraction (XRD), scanning electron microscopy (SEM), and Fourier-transform infrared spectroscopy (FTIR). Rheological tests showed that both Opuntia mucilage and the HPAM–mucilage blend displayed favorable viscoelastic behavior in saline environments (2% NaCl) at high concentrations (10,000 ppm). The mucilage also exhibited thermal stability above 200 °C, making it suitable for harsh reservoir conditions. Core flooding experiments conducted at 120 °C using core plugs from Algerian reservoirs revealed enhanced oil recovery performance. The recovery factors were 63.3% for HPAM, 84.35% for Opuntia mucilage, and 94.28% for the HPAM–mucilage blend. These results highlight not only the synergistic effect of the blend but also the standalone efficiency of the natural biopolymer in improving oil mobility and pore permeability. This study confirms the viability of using locally sourced biopolymers in EOR strategies. Opuntia ficus-indica mucilage offers a cost-effective, eco-friendly, and thermally stable alternative to conventional polymers for enhanced oil recovery, particularly in saline and high-temperature reservoirs such as Hassi Messaoud in Algeria. Full article

This study presents the formulation and evaluation of a dual molecular weight polymer gel system composed of partially hydrolyzed polyacrylamide (HPAM) and crosslinked with polyethyleneimine (PEI) for water shut-off applications. A soft gel, designed for deep reservoir penetration, was formulated using 5000 ppm high-molecular-weight HPAM, while a rigid gel for near-wellbore blockage combined 5000 ppm high- and 5000 ppm low-molecular-weight HPAM. The gel system was designed at 65 °C, with an initial gelation time exceeding 8 h and viscosity values below 15 cP before gelation, ensuring ease of injection. Laboratory assessments included bottle testing, rotational and oscillatory rheological measurements, and core flooding to determine residual resistance factors (RRFs). The soft gel achieved a final strength of Grade D (low mobility), while the rigid gel reached Grade G (moderate deformability, immobile), according to Sydansk’s classification. RRF values reached 93 for the soft gel and 185 for the rigid gel, with both systems showing strong washout resistance and water shut-off efficiencies above 95%. These results demonstrate the potential of the HPAM/PEI gel system as an effective solution for conformance control in mature reservoirs with active aquifers. Full article

The S oilfield has adopted polymer flooding technology, specifically using partially hydrolyzed polyacrylamide (HPAM), to enhance oil recovery. During the production process, the S oilfield has generated a substantial amount of stable polymer flooding-produced liquid, in which oil droplets are difficult to effectively coalesce, presenting significant challenges in demulsification. This article focuses on the produced fluids from S Oilfield as the research subject, developing a molecular dynamics model for the stability analysis of production liquid, including the molecular dynamics model of an oil–pure water system, an oil–mineralized water system and an oil–polymer–mineralized water system, using the principle of molecular dynamics and combining it with the basic molecular model for analyzing the stability of polymer flooding-production liquid. Through the molecular dynamics simulation of the stability analysis of the extracted liquid, the changing rules of the molecular diffusion coefficient, radial distribution function (RDF), interfacial interaction energy, and interfacial tension under the action of ions as well as polymers in water were investigated. The simulation results demonstrate that the presence of all three inorganic salt ions (Na⁺, Ca²⁺, and Mg²⁺) reduces the interfacial tension between oil and water and stabilizes the interface. Following the addition of polymer, the interfacial tension of the system decreases and the interfacial interaction energy increases significantly, indicating that the stability of the system is significantly enhanced by HPAM. Full article

Gel system profile control and flooding is a novel profile control technology designed to address the issue of inefficient and ineffective water circulation in high water cut reservoirs during their later stages, demonstrating significant development potential. This system expands on the swept volume and enhances oil displacement efficiency, ultimately improving oil recovery. In this study, a new “injection well + intermediate well” configuration was employed to conduct physical simulation experiments on core modules using the gel system (Partially Hydrolyzed Polyacrylamide + Cr³⁺ cross-linker + Stabilizer). By adjusting the gel system dosage and the location of the intermediate well (0.123 PV + midway between the injection and production wells), changes in the recovery rate, water cut, seepage field, pressure field, oil saturation field, and swept volume were observed. The experimental results indicate that under these conditions, the model achieved the highest total recovery rate, with optimal displacement of remaining oil. Additionally, the gel system exhibited strong stability after formation and was resistant to breakthrough. Compared to single-injection well profile control and flooding, the configuration increased the recovery rate by 16.7%, demonstrating promising development prospects and application potential. Full article

In this work, a hydrophobically associative polymer (HAP) was mixed with β-cyclodextrin and epichlorohydrin polycondensate (β-CDP) in an aqueous solution to enhance the intermolecular interaction through host–guest inclusion between hydrophobes and cyclodextrins. Results showed that the host–guest interaction improved the thickening ability and viscoelasticity of the HAP solution and maintained its shear thinning behavior. The host–guest inclusion system demonstrated special viscosity–temperature curves and variable activation energy. Enhanced oil recovery (EOR) performance tests showed that the oil increment produced by the host–guest inclusion system was 5.5% and 9.3% higher than that produced by the HAP and the partially hydrolyzed polyacrylamide solution, respectively. Compared with pure HAP, β-CDP/HAP has a better comprehensive performance and is more attractive for EOR in high-temperature reservoirs. Full article

The application of nanocomposites based on polyacrylamide hydrogels as well as silica nanoparticles in various tasks related to the petroleum industry has been rapidly developing in the last 10–15 years. Analysis of the literature has shown that the introduction of nanoparticles into hydrogels significantly increases their structural and mechanical characteristics and improves their thermal stability. Nanocomposites based on hydrogels are used in different technological processes of oil production: for conformance control, water shutoff in production wells, and well killing with loss circulation control. In all these processes, hydrogels crosslinked with different crosslinkers are used, with the addition of different amounts of nanoparticles. The highest nanoparticle content, from 5 to 9 wt%, was observed in hydrogels for well killing. This is explained by the fact that the volumes of injection of block packs are counted only in tens of cubic meters, and for the sake of trouble-free workover, it is very important to preserve the structural and mechanical properties of block packs during the entire repair of the well. For water shutoff, the volumes of nanocomposite injection, depending on the well design, are from 50 to 150 m³. For conformance control, it is required to inject from one to several thousand cubic meters of hydrogel with nanoparticles. Naturally, for such operations, service companies try to select compositions with the minimum required nanoparticle content, which would ensure injection efficiency but at the same time would not lose economic attractiveness. The aim of the present work is to develop formulations of nanocomposites with increased structural and mechanical characteristics based on hydrogels made of partially hydrolyzed polyacrylamide crosslinked with resorcinol and paraform, with the addition of commercially available nanosilica, as well as to study their thermal degradation, which is necessary to predict the lifetime of gel shields in reservoir conditions. Hydrogels with additives of pyrogenic (HCSIL200, HCSIL300, RX380) and hydrated (white carbon black grades: ‘BS-50’, ‘BS-120 NU’, ‘BS-120 U’) nanosilica have been studied. The best samples in terms of their structural and mechanical properties have been established: nanocomposites with HCSIL200, HCSIL300, and BS-120 NU. The addition of hydrophilic nanosilica HCSIL200 in the amount of 0.4 wt% to a hydrogel consisting of partially hydrolyzed polyacrylamide (1%), resorcinol (0.04%), and paraform (0.09%) increased its elastic modulus by almost two times and its USS by almost three times. The thermal degradation of hydrogels was studied at 140 °C, and the experimental time was converted to the exposure time at 80 °C using Van’t Hoff’s rule. It was found that the nanocomposite with HCSIL200 retains its properties at a satisfactory level for 19 months. Filtration studies on water-saturated fractured reservoir models showed that the residual resistance factor and selectivity of the effect of nanocomposites with HCSIL200 on fractures are very high (226.4 and 91.6 for fracture with an opening of 0.05 cm and 11.0 for porous medium with a permeability of 332.3 mD). The selectivity of the isolating action on fractured intervals of the porous formation was noted. Full article

Long-term polymer flooding exacerbates reservoir heterogeneity, intensifying intra- and inter-layer conflicts, which makes it difficult to recover the remaining oil. Therefore, further improvement in oil recovery after polymer flooding is essential. In this study, a weak gel system was successfully synthesized, and possesses a distinct network structure that becomes more compact as the concentration of partially hydrolyzed polyacrylamide increases. The network structure of the weak gel system provides excellent shear resistance, with its apparent viscosity significantly higher than that of partially hydrolyzed polyacrylamide solution. The weak gel system exhibits typical pseudo-plastic behavior, which is a non-Newtonian fluid as well as a viscoelastic fluid. Additionally, the weak gel system’s elasticities exceed its viscosities, and longer crosslinking time further enhances the viscoelasticity. The weak gel system achieves superior conformance control and enhanced oil recovery in highly heterogeneous reservoirs compared to partially hydrolyzed polyacrylamide solutions. The weak gel system is more suited to low-permeability reservoirs with strong heterogeneity, as its effectiveness in conformance control and oil recovery increases with greater reservoir heterogeneity. Enhanced oil recoveries of the weak gel system in low-permeability sandpacks increase from 22% to 48% with a rise in permeability ratios from 14.39 to 35.64 after polymer flooding. Full article

The dilute-foam dispersion system improves oil recovery by reducing interfacial tension between oil and water, altering wettability, and diverting displaced fluids by plugging larger pores. An optimized foaming system is obtained by formability evaluation experiments, in which the half-life for drainage and foaming volume by different types and concentrations of surfactants are analyzed, followed by the addition of partially hydrolyzed polyacrylamide (HPAM) with varied concentrations to enhance the foam stability. Using COMSOL Multiphysics 5.6 software, the Jamin effect and plugging mechanism of the water–gas dispersion system in narrow pore throats were simulated. This dispersion system is applied to assist CO₂ huff-n-puff in a low-permeability core, combined with the online NMR method, to investigate its effects on enhanced oil recovery from the pore scale. Core-flooding experiments with double-pipe parallel cores are then performed to check the effect and mechanism of this dilute-foam dispersion system (DFDS) on enhanced oil recovery from the core scale. Results show that foam generated by combining 0.6% alpha-olefin sulfonate (AOS) foaming agent with 0.3% HPAM foam stabilizer exhibits the strongest foamability and the best foam stability. The recovery factor of the DFDS-assisted CO₂ huff-n-puff method is improved by 6.13% over CO₂ huff-n-puff, with smaller pores increased by 30.48%. After applying DFDS, the minimum pore radius for oil utilization is changed from 0.04 µm to 0.029 µm. The calculation method for the effective working distance of CO₂ huff-n-puff for core samples is proposed in this study, and it is increased from 1.7 cm to 2.05 cm for the 5 cm long core by applying DFDS. Double-pipe parallel core-flooding experiments show that this dispersion system can increase the total recovery factor by 17.4%. The DFDS effectively blocks high-permeability layers, adjusts the liquid intake profile, and improves recovery efficiency in heterogeneous reservoirs. Full article

HPAM/PEI gel is a promising material for conformance control in hydrocarbon reservoirs. However, its use in low-permeability reservoirs is limited by the high polymer concentrations present. In this study, the gelation performance of an HPAM/PEI system with HPAM < 2.0 wt.% was systematically investigated. The gelation time for HPAM concentrations ranging from 0.4 to 2.0 wt.% varied from less than 1 h to 23 days, with the highest gel strength identified as grade H. The hydrodynamic radius manifested the primary effect of HPAM on the gelation performance. Branched PEI provided superior gelation performance over linear PEI, and the gelation performance was only affected when the molecular weight of the PEI varied significantly. The optimal number ratio of the PEI-provided imine groups and the HPAM-provided carboxylic acid functional groups was approximately 1.6:1~5:1. Regarding the reservoir conditions, the temperature had a crucial effect on the hydrodynamic radius of HPAM. Salts delayed the gelation process, and the order of ionic influence was Ca²⁺ > Na⁺ > K⁺. The pH controlled the crosslinking reaction, primarily due to the protonation degree of PEI and the hydrolysis degree of HPAM, and the most suitable pH was approximately 10.5. Plugging experiments based on a through-type fracture showed that multi-slug plugging could significantly improve the plugging performance of the system, being favorable for its application in fractured low-permeability reservoirs. Full article

The application results of profile control and water plugging technology are highly related to the gelation time and strength of phenolic resin hydrogel. In this work, a hydrogel solution was prepared by fully mixing the prepared polymer solution with a crosslinker. The static gelation process of PFR hydrogel in ampoule bottles and porous media was analyzed by changes in the viscosity and residual resistance coefficient. Then, the dynamic gelation of the PFR hydrogel in porous media was tested using a circulating flow device, and the changes in viscosity and injection pressure were analyzed during the dynamic gelation process. Finally, the effects of the polymer concentration and crosslinker concentration on dynamic gelation were analyzed. The initial gelation time and final gelation time in porous media were 1–1.5 times and 1.5–2 times those in ampoule bottles under static conditions, respectively. The initial dynamic gelation time in porous media was 2–2.5 times and 1.5–2 times the initial static gelation times in ampoule bottles and porous media, respectively. The final dynamic gelation time was four times and two times the initial static gelation times in ampoule bottles and porous media, respectively. The production after dynamic gelation in porous media comprised hydrogel aggregates and water fluid, leading to a high injection pressure and low viscosity of the produced liquid. As the concentration of polymer and crosslinker increased, the dynamic gelation time was shortened and the gel strength was increased. In the dynamic gelation process in porous media, the phenol resin hydrogel could migrate deeply, but it was limited by the concentrations of the polymer and crosslinker. The results of subsequent water flooding showed that the polymer hydrogel had a good plugging ability after dynamic gelation. The deep reservoir could only be blocked off in the subsequent water flooding process when the migration of hydrogel happened in the dynamic gelation process. Full article

Polymer flooding has achieved considerable success in medium–high permeability reservoirs. However, when it comes to low-permeability reservoirs, polymer flooding suffers from poor injectivity due to the large molecular size of the commonly used high-molecular-weight (high-MW) partially hydrolyzed polyacrylamides (HPAM). Herein, an amphiphilic polymer (LMWAP) with a low MW (3.9 × 10⁶ g/mol) was synthesized by introducing an amphiphilic monomer (Allyl-OP-10) and a chain transfer agent into the polymerization reaction. Despite the low MW, LMWAP exhibited better thickening capability in brine than its counterparts HPAM-1800 (MW = 1.8 × 10⁷ g/mol) and HPAM-800 (MW = 8 × 10⁶ g/mol) due to the intermolecular hydrophobic association. LMWAP also exhibited more significant shear-thinning behavior and stronger elasticity than the two counterparts. Furthermore, LMWAP possesses favorable oil–water interfacial activity due to its amphiphilicity. The oil–water interfacial tension (IFT) could be reduced to 0.88 mN/m and oil-in-water (O/W) emulsions could be formed under the effect of LMWAP. In addition, the reversible hydrophobic association endows the molecular chains of LMWAP with dynamic association–disassociation transition ability. Therefore, despite the similar hydrodynamic sizes in brine, LMWAP exhibited favorable injectivity under low-permeability conditions, while the counterpart HPAM-1800 led to fatal plugging. Furthermore, LMWAP could enhance oil recovery up to 21.5%, while the counterpart HPAM-800 could only enhance oil recovery by up to 11.5%, which could be attributed to the favorable interfacial activity of LMWAP. Full article