High-molecular-weight partially hydrolyzed polyacrylamide (HPAM) has extensively used in enhanced oil recovery (EOR) process; however, it suffers from poor injectivity into low-permeability oil reservoirs and compromised long-term thermal stability under reservoir conditions. To address these challenges, a viscoelastic surfactant, 3-(N-erucamidopropyl-N,N-dimethyl ammonium) betaine (EDAB), was developed and systematically compared with HPAM. Experimental results demonstrate that EDAB outperforms HPAM in thermal resilience, salt tolerance, and interfacial activity. Unlike HPAM's thermal thinning behavior, EDAB displays thermo-thickening properties, with viscosity rising from 225 to 366 mPa·s as temperature increases from 25 to 55 ℃. EDAB maintains 100% viscosity retention under 80 mg·L⁻¹ Ca²⁺ or Mg²⁺, whereas HPAM experiences 46% viscosity loss under identical ionic conditions. Core-flooding tests conducted under simulated Daqing oil reservoir conditions indicate that EDAB achieves a 1.4% higher incremental oil recovery factor than HPAM with equal initial solution concentration. When HPAM was employed as a mobility control for pre- or post-flush, EDAB elevates the recovery factor by 13.9% over water flooding. These comparative analyses underscore the potential of EDAB as a thermally stable, salt-insensitive alternative to HPAM, offering an optimized chemical strategy for EOR in challenging reservoir environments. The findings provide empirical validation for surfactant-based solutions to address HPAM's operational constraints in low-permeability formations.

Viscoelastic surfactants (VES) are often used as viscous diverters in acidizing stimulation to prolong the acid consumption time and maximize zonal coverage of the acid for improving well productivity. However, the ceiling temperature of commercial VES cannot exceed 120 ℃ in practical use because of the poor thermal stability and fragile molecular structure, hindering their implementation in high-temperature oil reservoirs, i.e., ≥150 ℃. Here we synthesized a novel C₂₂-tailed diamine, N-erucaminopropyl-N,N-dimethylamine (EDPA), and examined comparatively its rheological behavior, assemblies morphology and molecular stability in 20 wt% HCl with a commercial VES, erucyl dimethyl amidopropyl betaine (EDAB). The feasibility of EDPA for acidizing stimulation was assessed by acid etching of carbonate rock with its HCl solution at 150 ℃. Rheological results showed that the 2.5 wt% EDPA–20 wt% HCl solution maintains stable viscosity of 90 mPa s at 150 ℃ for 60 min, while that of 2.0 wt% EDAB HCl solution is just 1 mPa s under identical conditions. ¹H NMR spectra and cryo-TEM observations revealed that the chemical structure and self-assembled architectures of EDPA remained intact in such context, but the EDAB suffered from degradation due to the hydrolysis of the amide group, accounting for the poor heat-resistance and acid-tolerance. The reaction rate of 2.5 wt% EDPA HCl solution with carbonate rock was one order of magnitude lower than that of 20 wt% HCl solution at 150 ℃, underpinning the potential of EDPA to be used in the high-temperature reservoirs acidizing. This work improved the thermal tolerance of VES in highly concentrated HCl solution, paving a feasible way for the acidization of high-temperature reservoir environments (~150 ℃).

Undesirable gas channeling always occurs along the high-permeability layers in heterogeneous oil reservoirs during water-alternating-CO₂ (WAG) flooding, and conventional polymer gels used for blocking the “channeling” paths usually suffer from either low injectivity or poor gelation control. Herein, we for the first time developed an in-situ high-pressure CO₂-triggered gel system based on a smart surfactant, N-erucamidopropyl-N,N-dimethylamine (UC₂₂AMPM), which was introduced into the aqueous slugs to control gas channeling in WAG processes. The water-like, low-viscosity UC₂₂AMPM brine solution can be thickened by high-pressure CO₂ owing to the formation of wormlike micelles (WLMs), as well as their growth and shear-induced structure buildup under shear flow. The thickening power can be further potentiated by the generation of denser WLMs resulting from either surfactant concentration augmentation or a certain range of heating, and can be impaired via pressurization above the critical pressure of CO₂ because of its soaring solvent power. Core flooding tests using heterogeneous cores demonstrated that gas channeling was alleviated by plugging of high-capacity channels due to the in-situ gelation of UC₂₂AMPM slugs upon their reaction with the pre- or post-injected CO₂ slugs under shear flow, thereupon driving chase fluids into unrecovered low-permeability areas and producing an 8.0% higher oil recovery factor than the conventional WAG mode. This smart surfactant enabled high injectivity and satisfactory gelation control, attributable to low initial viscosity and the combined properties of one component and CO₂-triggered gelation, respectively. This work could provide a guide towards designing gels for reducing CO₂ spillover and reinforcing the CO₂ sequestration effect during CO₂ enhanced oil recovery processes.

Polymer flooding has been witnessed an effective technology for enhancing oil recovery from medium-to low-permeability reservoirs; however, direct visualization of polymer solution flow in such reservoir condition is still lacking. In this work, a three-dimensional (3D) core-on-a-chip device with a permeability of around 200 mD was prepared and employed to visualize the pore-scale flow and displacement of a self-adaptive polymer (SAP, 8.7 × 10⁶ g·mol⁻¹)−whose microscopic association structure and macroscopic viscosity can reversibly change in response to shear action−versus partially hydrolyzed polyacrylamide (HPAM), by recording their flow curves, monitoring dynamic transportation process via particle imaging velocimetry, and building 3D structure of remaining oil. The results show that, in single-phase flow, all polymer solutions exhibit flow thinning and then thickening regions as flow rate increases, but the transition between two regimes occurs at a small Weissenberg number (10⁻³−10⁻¹) in this medium-permeable condition. In contrast to HPAM-1 with close weight-average molecular weight (M_w), the adaptive character not only extends SAP's shear-govern region, allowing SAP to propagate piece by piece and achieve higher accessible pore volume, but it also enhances the elastic resistibility of polymer in the extension-dominated regime, increasing the microscopic displacement efficiency. These two effects result in 1.5–3 times more oil recovery factor for SAP than for HPAM-1. Regarding ultra-high-M_w HPAM-2 (25 × 10⁶ g·mol⁻¹), plugging and chain degradation do occur, thus producing lower oil recovery than SAP. This work provides a direct approach for in-situ assessment of polymer-based displacing system under a more authentic condition of practical reservoirs.