Asphaltenes are known for causing flow assurance problems in numerous oil fields.

The continuous growth in global energy and chemical raw material demand has drawn significant attention to the development of heavy oil resources. A primary challenge in heavy oil extraction lies in reducing crude oil viscosity. Alkali–surfactant–polymer (ASP) flooding technology has emerged as an effective method for enhancing heavy oil recovery. However, the chromatographic separation of chemical agents presents a formidable obstacle in heavy oil extraction. To address this challenge, we utilized a free radical polymerization method, employing acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, lauryl acrylate, and benzyl acrylate as raw materials. This approach led to the synthesis of a multifunctional amphiphilic polymer known as PAALB, which we applied to the extraction of heavy oil. The structure of PAALB was meticulously characterized using techniques such as infrared spectroscopy and Nuclear Magnetic Resonance Spectroscopy. To assess the effectiveness of PAALB in reducing heavy oil viscosity and enhancing oil recovery, we conducted a series of tests, including contact angle measurements, interfacial tension assessments, self-emulsification experiments, critical association concentration tests, and sand-packed tube flooding experiments. The research findings indicate that PAALB can reduce oil–water displacement, reduce heavy oil viscosity, and improve swept volume upon injection into the formation. A solution of 5000 mg/L PAALB reduced the contact angle of water droplets on the core surface from 106.55° to 34.95°, shifting the core surface from oil-wet to water-wet, thereby enabling oil–water displacement. Moreover, A solution of 10,000 mg/L PAALB reduced the oil–water interfacial tension to 3.32 × 10⁻⁴ mN/m, reaching an ultra-low interfacial tension level, thereby inducing spontaneous emulsification of heavy oil within the formation. Under the condition of an oil–water ratio of 7:3, a solution of 10,000 mg/L PAALB can reduce the viscosity of heavy oil from 14,315 mPa·s to 201 mPa·s via the glass bottle inversion method, with a viscosity reduction rate of 98.60%. In sand-packed tube flooding experiments, under the injection volume of 1.5 PV, PAALB increased the recovery rate by 25.63% compared to traditional hydrolyzed polyacrylamide (HPAM) polymer. The insights derived from this research on amphiphilic polymers hold significant reference value for the development and optimization of chemical flooding strategies aimed at enhancing heavy oil recovery.

Some oil wells in the Tahe oilfield have been reported to produce extremely heavy oil due to asphaltene deposition. To enhance the flow of crude oil through the wellbore, engineers adopted the use of light oil from nearby wells to dissolve the heavy crude in the wells’ sections to maximize recovery from the Tahe oilfield. However, this mixing has led to the problem of accelerated asphaltene deposition, which often blocks the wellbore in the process. In this research, the factors that influence the stability of diluted heavy oil, temperature, and mixing ratio on asphaltene deposition characteristics under high pressure are studied using a high-temperature and high-pressure crude oil flow property experimental device based on the differential pressure method. The results under high pressure show that the initial deposition pressure of asphaltene decreases as the experimental temperature increases. With an increase in the mixing light oil ratio, the initial deposition pressure of diluted heavy oil increases, and the deposition trend of asphaltene strengthens. The asphaltene accumulation and deposition will be aggravated by filling quartz sand and pipe diameter changes. The research here is helpful to understand the deposition characteristics of asphaltene during the production of diluted heavy oil. It offers significant guidance in the prevention and control of asphaltene precipitation in heavy oil wells.

In this paper, the rheological behavior of bitumen as a function of asphaltene concentration has been studied. Several bitumen samples having distinctly different amounts of asphaltene were prepared and characterized using differential scanning calorimetry and rheological measurements. The glass transition temperature of bitumen increases with an increase of the asphaltene concentration. This correlation can be used to estimate the asphaltene concentration of bitumen samples using DSC measurements. Small-amplitude oscillatory shear data for the bitumen-derived samples were fit by the generalized Maxwell model with good agreement. A constitutive model is proposed, where the zero-shear complex viscosity of the bitumen sample is a strong function of the asphaltene concentration, and it can be used to predict the asphaltene concentration.