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CO 2 foam can be used for mobility control and blocking gas breakthrough channels during CO 2 injection for enhanced oil recovery, and specially designed and formulated foam agents are needed to enhance the stability of the foams especially under reservoir conditions. In this study, the performance of CO 2 foams with various surfactants has been investigated, including amide based surfactants (e.g. coconut monoethanol amide (CMEA), lauryl diethanol amide (LDEA)), amine based surfactants (cocoacyl propyl dimethylamine (UC 11 AMPM)), sodium dodecyl sulfate (SDS) and its mixtures with the amides and amines. A visualized high pressure and high temperature foam meter and a sand-pack flooding setup were used to assess the foam's performance, along with the surface tension measurement of the surfactant solutions in the presence of CO 2. The influence of temperature, the surface tension of the aqueous solution, and SDS on CO 2 foam performance of amide and amine based surfactant were investigated. The experimental results indicate that the amide or amine based surfactant alone all show poor foam performance, while their CO 2 foam stability and their mobility control capability can be greatly enhanced at high temperature up to 100 °C with the salinity of 50000 mg/L. After adding SDS to CMEA, LDEA, or UC 11 AMPM, an excellent synergistic effect can be formed among the molecules, which can reduce the surface tensions of individual surfactant solution and enhance the stability of CO 2 foams. • The CO 2 foam performance of amine and amide based surfactants were tested at HTHP conditions. • Stable CO 2 foams can be generated by amine surfactant with SDS at temperature up to 130 °C. • The synergistic effect of amine based surfactant with SDS has been demonstrated for CO 2 foams at high temperature. [ABSTRACT FROM AUTHOR]

Amine-surfactant can be converted to be cationic surfactant in water solution saturated with CO 2 , which can enhance their foaming ability and foam stability, and the foaming ability can be switched off or on by CO 2 or replacing with N 2 with heating, so the amine-surfactants have great potential for smart mobility control to gas channeling during CO 2 flooding. In this study, three alkyl propyl dimethylamines with different carbon chain length (R = 11, 17 and 22, named as UC 11 AMPM, UC 17 AMPM, and UC 22 AMPM, respectively), were investigated as CO 2 responsive foam agent, and their foam performance under static and dynamic condition was tested up to 130 °C and 10.5 MPa using a visualized foam meter and a sand-pack flooding setup. The influence of carbon chain length on bulk solution viscosity, surface activity, foaming ability, and foam quality on bulk foam stability were measured and analyzed. The experimental results indicate that the three amine surfactants all demonstrate well CO 2 responsibility and CO 2 foaming ability, and show well switchable by CO 2 and N 2 at high temperature and high pressure (HTHP) condition. With the carbon chain length increasing, the surfactant shows higher absorption on the foam films, and bulk solution has a higher viscosity, which can decrease de-foam velocity and enhance the foam stability, as a result, the surfactant shows higher mobility control ability. • The CO 2 foam performance of three amine surfactants were tested at HTHP conditions. • The influence of carbon chain length on foam performance, bulk viscosity, surface active and foam quality was analyzed. • Alkyl propyl dimethylamines have well mobility control ability to CO 2 at high temperature-tolerance (up to 130 °C). [ABSTRACT FROM AUTHOR]

Abstract In-situ conversion process (ICP) can be an effective technique for the development of oil shale and ultra heavy oils, in which kerogen or heavy components will be cracked into light oils and gases via underground heating and pyrolysis, and the retorted oil can be recovered via conventional extraction techniques. Heating of targeted formation can be conducted using electrical heaters installed in vertical or horizontal wells, while a slow heating rate and lack of driving energy for oil production are the main issues of the conventional in-situ conversion process. In this study, an innovative nitrogen injection assisted in-situ conversion process (NAICP) was proposed to increase formation heating rate and improve oil production from oil shale. Reaction models of kerogen pyrolysis at elevated temperature were established, along with models for the evolution of porosity and permeability of oil shale formation during the pyrolysis process. The performance of nitrogen injection on the effectiveness of the ICP was then investigated through reservoir numerical simulation. The simulation results show that additional nitrogen injection can improve the heating rate of the oil shale formation, enhance oil production and energy efficiency in comparison with the conventional ICPs, which can be attributed to enhanced heat convection, pressurization effect and gas driving mechanism. Nitrogen injection assisted in-situ conversion process can be a promising technique for the exploitation of oil shale. Highlights • Nitrogen injection assisted in-situ process for oil shale was proposed. • The advantages of nitrogen injection assisted in-situ process were studied. • The mechanism of nitrogen injection to improve oil production performance was studied. • The effects of heating temperature and nitrogen injection rate were studied. [ABSTRACT FROM AUTHOR]

In-situ upgrading (ISU) via downhole heating is an innovative and efficient technique for oil shale and ultra heavy oil recovery. However, low heat transfer in the ISU process can limit its application in large scale. Therefore, efficient air injection assisted ISU process (AAISU) was proposed. In this study, reservoir stimulation of the AAISU process was performed to investigate the effect of air injection on heat transfer, oil production performance and energy conversion efficiency, as compared to the original ISU process. The influences of important engineering aspects were investigated, including well pattern, well distance, heating temperature and air injection rate for the field application of the AAISU technique. The reservoir stimulation results indicate that heat transfer rate can be significantly accelerated by air injection, and the average reservoir temperature during the AAISU can be increased to 250 °C after one year, in comparison with that of 116 °C in the ISU process. The contribution of air injection on the total heat transfer can be approached to 60%. Air injection can also enhance oil recovery and improve the energy efficiency. Heating temperature and air injection rate also have significant impact on the performance of the AAISU process. For a 15 m × 15 m × 10 m geo-model, increase of the heating temperature from 250 °C to 350 °C and air injection rate from 500 m3/day to 1000 m3/day can result in improved energy efficiency. However, heating temperature above 350 °C and the air injection rate over 1000 m3/day can led to a decreased energy efficiency, due to higher energy consumption on electrical heating and high rate of air injection. • Air injection assisted in situ upgrading process (AAISU) of ultra heavy oils was proposed. • The effect of air injection on heat transfer was studied. • The influence of well pattern and well distance on the AAISU was investigated. • The influence of heating temperature and air injection rate on the AAISU process was evaluated. [ABSTRACT FROM AUTHOR]