• Energy Research

Performance of cyclic CO2 injection as an enhanced oil recovery (EOR) technique in a light crude oil system was experimentally investigated. Series of cyclic CO2 injection tests were designed and c...

The recovery performance of immiscible and miscible CO2 huff-and-puff processes for enhanced oil recovery (EOR) in a light crude oil sample was experimentally investigated. The minimum miscibility pressure (MMP) of the original light crude oil–CO2 system was determined by means of the vanishing interfacial tension technique and found to be MMP = 9.18 MPa. Then, the solubility of the CO2 in the light crude oil and oil swelling factor due to the CO2 dissolution in the oil phase were determined at T = 30 °C and various equilibrium pressures ranging from atmospheric pressure to Peq = 12.55 MPa. Later, series of immiscible and miscible CO2 huff-and-puff tests were designed and carried out at various operating pressures (i.e., Pop = 5.38–10.34 MPa). The results of the experiments showed that for secondary CO2 huff-and-puff tests performed at the operating pressures below the MMP, the ultimate oil recovery factor is quite low. It was also found that in immiscible CO2 huff-and-puff (i.e., Pop < MMP) scenarios, th...

Abstract Steam assisted gravity drainage is the main technologically and economically feasible method for in situ bitumen extraction. However, SAGD is energy intensive with economic and environmental challenges. Steam-solvent coinjection has proposed to improve SAGD performance, where hydrocarbon solvent is simultaneously injected with steam to increase the production rate and lower the steam-oil-ratio. The addition of solvent, however, complicates an already complex multicomponent thermal-chemical process. Microfluidics is well suited to quantify the pore-scale of steam-solvent coinjection with a tight control over experimental parameters. In this study, a high-pressure high-temperature micromodel combined with optical and thermal imaging is used to probe the pore-scale of steam-solvent coinjection process at relevant reservoir conditions. The effects of butane and hexane, as well as two industrial solvents, condensate and naphtha, on the pore-scale mechanisms are quantified and compared. The in situ thermal data is used to profile and analyze the condensation zone behavior and steam-solvent azeotropic temperature for all steam-solvent cases. We find that overall performance depends on the difference between steam-solvent azeotropic temperature and steam saturation temperature, the degree of solvent-bitumen dilution, and the degree of asphaltene precipitation in the condensing zone. In contrast with pure solvents and condensate, naphtha results in the highest recovery due to a higher steam-solvent azeotropic temperature, effective dilution, with minimal asphaltene deposition.

A nanofluidic platform (Nanomodel) in fast screening enhanced tight oil recovery strategies through direct observation.

Abstract Floods were conducted using rock–fluid systems consisting of carbonate cores from Binak reservoir, which is located in southwest of Iran, oil and brine. The coreflood protocol consisted of a series of steps including brine saturation, absolute permeability determination, flooding with oil to initial oil saturation, endpoint oil permeability determination, and, finally, nitrogen and carbon dioxide water-alternating-gas (WAG) injections. The effect of slug size on oil recovery was investigated using immiscible nitrogen (N2) WAG injection and the amount of oil recovered was compared with continuous injection of N2. Experimental results show that ultimate oil recovery is not very sensitive to changing the slug sizes for N2 WAG injection, although the slug size of 0.15 pore volume (PV) injection is better than others. As less PV is injected, a higher oil production rate is achieved. Also, N2 WAG flood appeared to be better in performance than continuous gas injection (CGI) of nitrogen. Carbon dioxide ...

AbstractThe minimum miscibility pressure (MMP) of crude oil–CO2 systems was determined through analyzing the experimental data of swelling/extraction tests. First, the oil swelling factor (SF) as a result of CO2 dissolution in a crude oil sample was determined at four different temperatures in the range of T=21–40 °C. In addition, three sets of swelling/extraction data of previous studies were collected and included so that more conclusive and satisfactory results can be obtained. The results demonstrated that the oil swelling factor increases with the equilibrium pressure (Peq), reaches the maximum value at light hydrocarbon extraction pressure (Pext), and then reduces with further increase in equilibrium pressure. It was found that the reduction behavior of oil swelling factor occurs in two distinct regions. In the upper extraction phase (UEP), the oil swelling factor decreased sharply at pressures just over extraction pressure and then declined gradually in what is called the lower extraction phase (LEP). Finally, the MMP of the crude oil–CO2 system at a specific temperature was estimated by finding the intersection of the linear regression correlation corresponding to each of the aforementioned regions (i.e., UEP and LEP). The crude oil–CO2 MMP was also determined by employing the vanishing interfacial tension (VIT) technique and a series of CO2 injection tests. Comparing the MMP values of the crude oil–CO2 systems determined by three methods revealed that the MMP values estimated by swelling/extraction data are in approximate agreement with those determined by the two other methods.

AbstractThis study was conducted to investigate the phase behaviour of CO2–brine and CO2–oil systems under various operating conditions. Through this study, CO2 solubility measurement tests were carried out for CO2–water, CO2–brine, and CO2–oil mixtures at various equilibrium pressures ranging Peq = 0.7–10.3MPa and temperatures ranging Texp = 21–40°C. Additionally, series of oil swelling/extraction tests were conducted at aforementioned experimental conditions using a see-through high- pressure cell to determine the oil swelling factor at various equilibrium conditions. CO2 solubility measurement tests showed that at constant temperatures, an increase in CO2 solubility value was observed for CO2–water, CO2–brine, and CO2–oil mixtures when the equilibrium pressure increases. Furthermore, as it was expected for all mixtures, the solubility of CO2 reduces with increased temperature. In this study, it was also found that at a constant temperature, the oil swelling factor, SF, increases up to a pressure so called extraction pressure, Pext, at which majority of the light to medium hydrocarbon groups in the oil phase are extracted by CO2 and vaporized into the CO2-rich phase. Additionally, it was observed that for the pressures higher than the extraction pressure, the oil swelling factor reduced with equilibrium pressure because more hydrocarbon components were extracted at higher pressures. The extraction pressure was determined at different experimental temperatures and results revealed that the extraction pressure increases by increasing experimental temperature. Comparison of the CO2 solubility values in oil at extraction pressures corresponding to different experimental temperatures also showed that the major hydrocarbon extraction occurs when a certain amount of CO2 has dissolved in the oil phase which is called threshold CO2 solubility, χth. The defined threshold CO2 solubility was found to be approximately the same for the CO2–oil mixture under this study at different temperatures.

Solvent bitumen extraction processes are alternatives to thermal processes with potential for improved economic and environmental performance. However, solvent interaction with bitumen commonly results in in situ asphaltene precipitation and deposition, which can hinder flow and reduce the process efficiency. Successful implementation requires one to select a solvent that improves recovery with minimal flow assurance problems. The majority of candidate industrial solvents are in the form of mixtures containing a wide range of hydrocarbon fractions, further complicating the selection process. In this study, we quantify the pore-scale asphaltene deposition using two commonly available solvent mixtures, natural gas condensate and naphtha, using a microfluidic platform. The results are also compared with those of two typical pure solvents, n-pentane and n-heptane, with all cases evaluated with both 50 and 100 μm pore-throat spacing. The condensate produced more asphaltenes and pore-space damage than the napht...

Carbon capture, storage, and utilization technologies target a reduction in net CO2 emissions to mitigate greenhouse gas effects. The largest such projects worldwide involve storing CO2 through enhanced oil recovery-a technologically and economically feasible approach that combines both storage and oil recovery. Successful implementation relies on detailed measurements of CO2-oil properties at relevant reservoir conditions (P = 2.0-13.0 MPa and T = 23 and 50 °C). In this paper, we demonstrate a microfluidic method to quantify the comprehensive suite of mutual properties of a CO2 and crude oil mixture including solubility, diffusivity, extraction pressure, minimum miscibility pressure (MMP), and contact angle. The time-lapse oil swelling/extraction in response to CO2 exposure under stepwise increasing pressure was quantified via fluorescence microscopy, using the inherent fluorescence property of the oil. The CO2 solubilities and diffusion coefficients were determined from the swelling process with measurements in strong agreement with previous results. The CO2-oil MMP was determined from the subsequent oil extraction process with measurements within 5% of previous values. In addition, the oil-CO2-silicon contact angle was measured throughout the process, with contact angle increasing with pressure. In contrast with conventional methods, which require days and ∼500 mL of fluid sample, the approach here provides a comprehensive suite of measurements, 100-fold faster with less than 1 μL of sample, and an opportunity to better inform large-scale CO2 projects.