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Collaborating Authors
Results
CO2 Foam Stabilized with Switchable Surfactants and Modified Nanoparticles Effected by PH and Salinity
Zhang, Xuan (China University of Petroleum East China) | Zhang, Guicai (China University of Petroleum East China) | Ge, Jijiang (China University of Petroleum East China) | Wang, Yanqing (The University of Tulsa)
Abstract Foam could increase the apparent viscosity of carbon dioxide (CO2) significantly and control the mobility. This work focused on the enhancement of CO2 foam stability with adding modified silica nanoparticles, which effected by the concentration ratio, pH and salinity. The results demonstrated that the interaction between the nanoparticles and surfactants was effected by both salinity and pH, and the mixing solution of 0.5 wt% NPs and 0.2 wt% C1202 was colloidal stable in high salinity brine at pH4.5 and 80 °C, while at high pH 6.5, the NPs will aggregate. Higher nanoparticles concentration with constant surfactant concentration would increase the solution colloidal stability due to lower density of surfactant adsorbing at nanoparticles surface. The interfacial tension between CO2 and water dropped to around 6mN/m significantly with surfactant C1202 and adding nanoparticles has slight effect on interfacial tension. However, the compression modulus increased maximum 3 times obviously calculated by the decrease of interfacial tension in shrinking process, which proved that due to strong and irreversible nanoparticles adsorption. Moreover, the core flooding results confirmed that adding NPs results in more viscous foam generation to reduce the CO2 mobility and the total oil recovery enhanced 17% comparing with water flooding. This mixing solution makes it possible to enhance CO2 foam stability at low pH and given high salinity, which is important to reduce gas mobility in reservoir conditions and, eventually, enhance oil recovery.
The CO2 Foam Stability Enhancement with Switchable Surfactant and Modified Silica Nanoparticles
Zhang, Xuan (China university of Petroleum, East China) | Wang, Yanqing (the University of Tulsa) | Da, Chang (the University of Texas at Austin) | Ge, Jijiang (China university of Petroleum, East China) | Zhang, Guicai (China university of Petroleum, East China) | Jiang, Ping (China university of Petroleum, East China) | Pei, Haihua (China university of Petroleum, East China)
Abstract When the silica nanoparticles (NPs) were modified with Glymo silane, the surface charge of NPs would change along with the silane coverage, which has an effect on the interaction with switchable surfactants. This study focused on the electrostatic force between the switchable surfactants and modified silica NPs with different coverage scale. At low pH 4.5, the ethoxylated amine surfactants switched to protonated state with quaternary ammonium group, that contains positive charge. However, when the silane coverage was higher than 1.0 µmol/m, the mixing solution could keep stable at 80°C due to the fewer negative charge at the NPs surface even in DI water. With increasing the ethylated groups of the switchable surfactant, the solution was more stable, which could be interpreted that the quaternary ammonium with positive charge was hindered by long EO chain. The bulk foam half-life extended twice with adding NPs in the surfactant solution, which proved that the CO2 foam was more stable and when the solution was slightly cloudy, the foam stability enhancement was more obvious, since the NPs more likely adsorbed at the CO2-liquid interface and enhanced the lamella stability at this state. Moreover, after adding NPs, the foam viscosity in sand-pack increased 1.5-2 times, comparing with surfactant alone and depended on the silane coverage of NPs, where the NPs with lower silane coverage have more positive effect on the foam stability enhancement. The mixing formula makes it possible to enhance CO2 foam stability at low pH and given high salinity, which is important to reduce gas mobility in reservoir conditions and, eventually, enhance oil recovery.
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Polymer-surfactant mixtures in aqueous solutions present unique rheological and interfacial properties that promote their applications in chemical flooding. The objective of this study is to investigate the interaction between anionic polyacrylamides and cationic surfactants in different temperature and salinity conditions and the potential application of the polymer-surfactant mixtures in carbonate reservoirs. Cationic surfactants were selected owing to low adsorption on carbonate rocks. Compatibility tests of polymer-surfactant mixtures were conducted in brine with different salinities to study the interaction between anionic polymers and cationic surfactants in the presence of salts. The effect of cationic surfactants on polymer viscosity at different temperatures was investigated. The compatibility of the mixtures of the cationic surfactants and the anionic polymers was significantly improved in high salinity injection water (with a total dissolved solid of 57,670 mg/L), compared with the compatibility in deionized water. This is attributed to the shielding of polymer and surfactant charges by the salts, which diminishes the electrostatic interaction between the chemicals. Rheological measurements indicated that the polymer viscosity increased in the presence of the cationic surfactant CAS-S or CAS-B. This effect was decreased at 90˚C. Other cationic surfactant CAS-1 or CAS-3 slightly increased the polymer viscosity at 25˚C and significantly decreased the viscosity at 90˚C. These observations can be explained based on the surfactants self-assembly. At room temperature, CAS-1 and CAS-3 form spherical micelles while CAS-S and CAS-B form wormlike micelles. The entanglement of the polymers with wormlike micelles explains the observed viscosity enhancement. At 90˚C, wormlike micelles became shorter which weakens this viscosity enhancement effect. In conclusion, the charges and self-assembly structures of surfactants play an important role in the performance of polymer-surfactant mixtures that should be taken into account in the design of optimal formulations. This work provides the insight of interaction between anionic polymers and cationic surfactants with different self-assembly structures for the potential application in improving oil production.
- North America > United States (0.94)
- Asia > Middle East (0.94)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
CO2/Water Foams Stabilized with Cationic or Zwitterionic Surfactants at Temperatures up to 120 °C in High Salinity Brine
Da, Chang (The University of Texas at Austin) | Elhag, Armo (Khalifa University of Science and Technology) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Alzobaidi, Shehab (The University of Texas at Austin) | Zhang, Xuan (China University of Petroleum) | Al Sumaiti, Ali (Khalifa University of Science and Technology) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University) | Johnston, Keith (The University of Texas at Austin)
Abstract Stabilization of CO2 in water (C/W) foams with surfactants at high temperatures and high salinities is challenging, due to limited solubility of surfactants in aqueous phase, foamability and thermal stability. The apparent viscosities of C/W foams has been raised to up to 35 cP with viscoelastic aqueous phases formed with a diamine surfactant, C16-18N(CH3)C3N(CH3)2 (Duomeen TTM), or a zwitterionic surfactant, cetyl betaine, at 120 °C in 22% total-dissolved-solids (TDS) brine. Duomeen TTM is switchable from the nonionic (unprotonated amine) state, where it is soluble in CO2, to the cationic (protonated amine) state in an aqueous phase under pH ~6. Therefore, it may be injected in either the aqueous phase or the CO2 phase. The formation of viscoelastic phases with both surfactants lowers the minimum pressure gradient (MPG), and strengthens the lamella against drainage and Ostwald ripening by making the external aqueous phase more viscous, leading to stable foam even at very high foam quality. Both surfactants were shown to have excellent thermal stability and to form unstable emulsions when mixed with oil (dodecane). The core flood results showed that strong foam could be easily generated with both surfactants at a superficial velocity of 4 ft/day. The oil/water (O/W) partition coefficient of Duomeen TTM was very sensitive to pH, while that of cetyl betaine was constant over a wide range of pH. The ability to stabilize C/W foams at high temperature and salinity conditions with a single thermally stable surfactant is of great benefit to a wide range of applications including EOR, CO2 sequestration and hydraulic fracturing.
- North America > United States > Texas (0.29)
- North America > United States > Illinois (0.28)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations (1.00)
- (4 more...)
Abstract Water-soluble polymers have been widely used in chemical enhanced oil recovery (EOR) either independently or part of surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) processes. The polymer viscosifies the injected water thereby reducing displacing fluid mobility and sweep efficiency. Key to efficient sweep is attaining a sustainable mobility control (i.e. maintenance of sufficient viscosity during the propagation in the reservoir). Therefore, long-term stability is a crucial parameter in screening of appropriate polymers for EOR application, especially in high temperature and high salinity reservoirs. Generally, the evaluation of polymer solution's long-term stability is time-consuming process. Accordingly, there is a need to develop fast and reliable means to assess the feasibility of polymers from a long-term stability standpoint. Different from the methods in the literature, this paper presents a new facile approach to evaluate the polymers in powder form and identify their molecular decomposition. The approach is correlated and confirmed against conventional long-term stability results obtained on polymer solutions. Thermogravimetric analysis (TGA) was used in this work to study the decomposition of polymers and their individual constituents. The derivative of TGA curve with respect to temperature is known as the DTG, which can clearly identify differences in decomposition rates of screened polymers. Furthermore, conventional long-term stability tests were performed on polymer solutions prepared in synthetic seawater with salinity of 57,670 ppm. The solutions were aged at a temperature of 95°C under anaerobic conditions and monitored by rheological measurements for viscosity loss, total organic carbon (TOC) analyses for material loss, and gel permeation chromatography (GPC) for molecular weight loss. The thermal stability of 12 commercial water soluble polymers was tested in this work. The long-term stability results are consistent with the TGA results. The two polymers showing good thermogravimetric thermal stability exhibited significant viscosity retention in conventional long-term stability tests. TOC and GPC results further supported the TGA results. The developed and demonstrated method provides a fast approach to screen polymer candidates for high temperature and high salinity reservoirs.
- Asia (1.00)
- North America > United States > Oklahoma (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)