To investigate enhanced oil recovery processes, we constructed a molecular model of a live heavy crude oil (digital oil) and studied the crude oil properties at the reservoir temperature and a wide range of pressures. We identified the liquid phase components of the digital oil by flash calculation and calculated the density and viscosity by molecular dynamics simulations. The calculated density and viscosity were in good agreement with experimental data. To evaluate the effectiveness of various solvents to enhance oil recovery, we calculated the oil property changes when different solvents were added to the digital oil. First, we compared methane and carbon dioxide (CO 2 ). The results indicated that CO 2 was more effective in terms of oil-viscosity reduction, oil swelling, and diffusion in the oil. Second, we evaluated the effectiveness of 11 different solvents: nitrogen, CO 2 , methane, ethane, propane, n-heptane, n-octane, toluene, and three xylene isomers (o-xylene, m-xylene, and pxylene). Ethane had the greatest effect on oil-viscosity reduction and oil swelling, and CO 2 had the highest diffusion coefficient. From these results, ethane and CO 2 are appropriate solvents for this crude oil. In addition, it is interesting to note that the decreases of the viscosity among the three xylene isomers were different, but there were no differences in the swelling factors and diffusion coefficients. The different rotation motion characteristics of the xylene isomers can account for the viscosity differences. Such information will be helpful for further development of digital oil models.

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"Nanoparticle-based enhanced oil recovery (Nano-EOR)" is an improved waterflooding assisted by nanoparticles dispersed in the injection water. Many laboratory studies have revealed the effectiveness of Nano-EOR. An evaluation of the EOR effect is one of the most critical items to be investigated. However, risk assessments and mitigation plans are as essential as investigation of its effectiveness for field applications. This study examined the items to be concerned for applying Nano-EOR to the Sarukawa oil field, a mature field in Japan, and established an organized laboratory and field tests workflow. This paper discusses a laboratory part of the study in detail. This study investigated the effect and potential risks of the Nano-EOR through laboratory experiments based on the workflow. The laboratory tests used surface-modified nanosilica dispersion, synthetic brine, injection water, and crude oil. The oil and injection water were sampled from a wellhead and injection facility, respectively, to examine the applicability of the EOR at the Sarukawa oil field. The items of the risk assessment involved the influence on an injection well's injectivity, poor oil/water separation at a surface facility, and contamination of sales oil. A series of experiments intended for the Sarukawa oil field showed that 0.5 wt. % nanofluid was expected to contribute to significant oil recovery and cause no damage on an injection well for the reservoir with tens of mD. This is considered a favorable result for applying Nano-EOR to Sarukawa oil field because it contains layers of tens mD. Furthermore, the experiments also showed that 0.5 wt.% nanofluid did not lead to poor oil/water separation and contamination of sales oil. Thus, field tests are designed with this concentration. This paper introduces the entire study workflow and discusses the detailed procedure and results of experiments investigating the Nano-EOR effect and potential risks.

Solvent Assisted-Steam Assisted Gravity Drainage (SA-SAGD) has been studied as a more efficient process for extracting bitumen from oil sands than the SAGD process. In the SA-SAGD process, solvent is injected with steam to decrease the viscosity of bitumen by dissolution of the condensed solvent. The dissolution of solvent causes a composition change of bitumen, which can lead to asphaltene precipitation. The effects of the asphaltene precipitation have been studied as part of a solvent-based recovery process such as Vapor Extraction (VAPEX). One of the advantages of the asphaltene precipitation is in-situ upgrading of the bitumen, whereas the disadvantage is that it causes a formation damage. To evaluate the effect of the asphaltene precipitation in the SA-SAGD process, it is essential to investigate the asphaltene precipitation under the conditions expected in the SA-SAGD process. However, it takes a lot of time to obtain sufficient data with a conventional method to quantify asphaltene precipitation under high-pressure/high- temperature (HP/HT) conditions. Therefore, the aim of this study is to develop an experimental procedure to evaluate the asphaltene precipitation with pressure/volume/temperature (PVT) apparatus in a reasonable time. The complex phenomenon at the edge of the chamber in the SA-SAGD process was simplified to a model of repetitions of mixing and drainage processes, and the experiment was configured in this manner. Solvent was added to a pre-diluted bitumen sample in a PVT cell. The supernatant liquid was sampled to analyze the asphaltene weight fraction remaining in the liquid phase and evaluate the asphaltene precipitation amount in the PVT cell. This process was repeated with increase in the solvent concentration. The asphaltene precipitation amount (APA) is calculated from the sample analysis data with recurrence relations under several assumptions. This procedure enables a wide range of APAs to be obtained from a mixture of bitumen and solvent in a single experiment, which enables sensitivity analysis under various conditions. In this research, the experiment was conducted under two different temperature conditions of 120°C and 150°C and the pressure was fixed at 3.5 MPa. The APA curves obtained from both experiments had almost the similar trend. Another important observation is that even the multi-component solvent (as used at the operation site) can still induce asphaltene precipitation under the HP/HT conditions expected in the SA-SAGD process.

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