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.

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Unconventional shale reservoirs have become a key player in the oil and gas industry to cover the world's energy demands. Traditionally, oil-based drilling fluids (OBM) are preferred to drill shale plays due to negligible chemical interactions. Nevertheless, strict environmental regulations have motived the industry to design water-based drilling fluids (WBM) capable to control the shale-water interactions, improving their performance. Still, conventional additives are too large to plug shales’ micro-fractures and nanopores. Thus, nanoparticles due to their unique size, shape, and properties can provide a solution for the WBM. This study focus on the design and evaluation of a customized nanoparticle water-based drilling fluid (NP-WBM) using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs). The main objective is to identify the optimal NP concentration to improve the rheological and filtration properties of the NP-WBM and evaluated its inhibition benefit. The NP selection was based on the characteristics of the Woodford shale obtained through x-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). NPs’ colloidal stability was analyzed in an alkaline environment with zeta-potential measurements. The concentration of NPs was evaluated below 1 wt.%. Laboratory measurements for the NP-WBM included API filtrate test (LTLP) and high-temperature/high-pressure (HTHP) test using a static filter press and rheological analysis with a rotational viscometer. To evaluated the inhibition benefit, the NP-WBM was tested against the Woodford shale by performing immersion and cutting dispersion tests. The results showed zeta-potential values below −30 mV for both nanomaterials, indicating good dispersibility of the NPs within the WBM. Also, significant improvements in the filtration properties were observed when adding 0.5 wt.% of SiO2-NPs with 0.25 wt.% of GNPs to the base fluid with no spurt-loss and minor effects on the rheological parameters. Higher concentrations did not show further improvements; thus the previous combination was selected as the optimal. Chemical interactions tests indicated that the Woodford shale might develop micro-fractures when exposed to water for long periods of time. However, no micro-fractures were observed when the rock was exposed to NPs. Furthermore, the NP-WBM reduced the cutting dispersion by 35.61% compared to the base fluid, showing superior inhibition properties even in high illitic shales that are prone to experience cuttings disintegration. NPs’ stability and benefits at low concentrations, indicates their potential to improve the design of WBM for unconventional shales, reducing the environmental impacts linked to the drilling operations.

Immiscible carbon dioxide (CO 2) injection is one of the highly applied enhanced oil recovery (EOR) methods due to its high oil recovery potential and its ability to store CO 2 in the reservoir. The main mechanism of immiscible CO 2 injection is oil swelling. Generally, oil swelling is measured experimentally or measured using modeling methods. This research conducts oil swelling experiments using a simplified method in order to easily and accurately measure oil swelling and determines some of the most significant factors that may impact oil swelling during CO 2 injection. The impact of varying CO 2 injection pressure, temperature, oil viscosity and oil volume on oil swelling capacity was investigated. The simplified method managed to accurately determine the value of oil swelling for all the experiments. One of the factors that was found to impact the method significantly was the oil volume used. The oil volume in the experimental vessel was found to be extremely important since a large oil volume may result in a false oil swelling value. The oil swelling results were compared to other researches and showed that the method applied had an accuracy of over 90% for all the results obtained. This research introduces a simple method that can be used to measure oil swelling and applies this method to investigate some of the factors that may impact the oil swelling capacity during immiscible CO 2 injection. Keywords Oil swelling • Immiscible carbon dioxide injection • Novel technique List of symbols S o Oil swelling V so Volume of swelled oil V uo Volume of unswelled oil P Pressure of CO 2 V Volume occupied by the experimental vessel z Compressibility factor of CO 2 n Number of moles R Universal gas constant T Temperature at which the experiment is conducted 1 Initial conditions at the beginning of the experiment 2 Final conditions after the experiment was concluded IFT Interfacial tension