Asphaltene is a component of crude oil that has been reported to cause severe problems during production and transportation of the oil from the reservoir. It is a solid component of the oil that has different structures and molecular makeup which makes it one of the most complex components of the oil. This research provides a detailed review of asphaltene properties, characteristics, and previous studies to construct a guideline to asphaltene and its impact on oil recovery. The research begins with an explanation of the main components of crude oil and their relation to asphaltene. The method by which asphaltene is quantified in the crude oil is then explained. Due to its different structures, asphaltene has been modeled using different models all of which are then discussed. All chemical analysis methods that have been used to characterize and study asphaltene are then mentioned and the most commonly used method is shown. Asphaltene will pass through several phases in the reservoir beginning from its stability phase up to its deposition in the pores, wellbore, and facilities. All these phases are explained, and the reason they may occur is mentioned. Following this, the methods by which asphaltene can damage oil recovery are presented. Asphaltene rheology and flow mechanism in the reservoir are then explained in detail including asphaltene onset pressure determination and significance and the use of micro- and nanofluidics to model asphaltene. Finally, the mathematical models, previous laboratory, and oilfield studies conducted to evaluate asphaltene are discussed. This research will help increase the understanding of asphaltene and provide a guideline to properly study and model asphaltene in future studies.

Summary: The stimulation of unconventional reservoirs to improve oil productivity in tight formations of shale basins is a key objective in hydraulic fracturing treatments. Such stimulation can be made by reliable fracture fluids that have a high viscosity and elasticity to suspend the proppant in the fracture networks. Recently, due to several operational and economic reasons, the oil industry began using high-viscosity friction reducers (HVFRs) as direct replacements for linear and crosslinked gels. However, some issues can limit the capability of HVFRs to provide effective sand transport, including the high fluid temperature during fracture treatment inside the formations. This may lead to unstable fracture fluids caused by a decrease in the interconnective strength between the fluid chains, which results in reduced viscosity and elasticity. This study comprehensively investigated HVFRs in comparison with guar at various temperatures. An HVFR at 4 gallons per thousand gallons of water (gpt) and guar at 25 pounds per thousand gallons of water (ppt) were selected based on fluid rheology tests and hydraulic fracture execution field results. The rheological measurements of both fracture fluids were conducted at different temperature values (i.e., 25, 50, 75, and 100°C). Static and dynamic proppant settling tests were also conducted at the same temperatures. The results showed that the HVFR provided better proppant transport capability than the guar. The HVFR had better thermal stability than guar, but its viscosity and elasticity decreased significantly when the temperature exceeded 75°C. An HVFR can carry and hold the proppant more deeply inside the fracture than liner gel, but that ability decreases as the temperature increases. Therefore, using conditions that mimic field conditions to measure the fracture fluid rheology, proppant static settling velocity, and proppant dune development under a high temperature is crucial for enhancing the fracture treatment results.

Carbon dioxide (CO₂) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO₂injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO₂in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO₂injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO₂injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO₂injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO₂injection in hydrocarbon reservoirs.