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Collaborating Authors
Geng, Jiaming
Experimental Study on Charged Nanogels for Interfacial Tension Reduction and Emulsion Stabilization at Various Salinities and Oil Types
Geng, Jiaming (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Han, Pu (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology) | Bai, Baojun (Department of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology)
Abstract Nanoparticles have been systematically investigated for their EOR mechanisms, such as rock wettability alternation, oil displacement by disjoining pressure, and the stabilization of emulsion and foam. Nanogels are nano-sized crosslinked polymeric particles that have the properties of both nanoparticles and hydrogels. The goal of this study is to investigate the oil-water interfacial behavior in the presence of nanogels, especially the dynamic interfacial tension and the stability of oil-in-water (o/w) emulsions. The nanogels synthesized in this study are able to reduce the oil-water interfacial tension and stabilize the o/w emulsions. The diameter and zeta-potential of the charged nanogels are dramatically influenced by the brine salinity whereas the neutral charged nanogels are barely affected by salt. The synthesized nanogels are stable in distilled water and brines at room temperature for more than 60 days. The dynamic interfacial tension results show that the nanogels are able to reduce the oil-water interfacial tension to as much as 1/30 of the original value. In addition, the interfacial tension reduction is more significant at high salinity (ranging from 10,000 to 50,000 ppm NaCl concentration). Emulsion stability results demonstrated that the stability of emulsified oil drops was controlled by both the strength of the adsorbed nanogel layers and the interactions among oil drops. The salt dependent interfacial tension and emulsion stability indicated that the appropriate charged nanogel can be a promising candidate for enhanced oil recovery.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.84)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
Laboratory Screening Tests to Further Characterize Low-Salinity Waterflooding in Low-Permeability Sandstone Reservoir
Alhuraishawy, Ali K. (Missan Oil Company, Missouri University of Science and Technology) | Almansour, Abdullah (King Abdulaziz City for Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology)
Abstract The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The objective of this study was to test the ability of low-salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, interfacial, core flooding, and zeta potential tests. Three key factors were studied: salinity of the injected water, type of salt, and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. Berea sandstone was used in all experiments. Sodium chloride (NaCl) and calcium chloride (CaCl2) were used to prepare the brine. The imbibition test and core flooding results showed that the oil recovery increased as brine concentration decreased for both sodium chloride and calcium chloride. Sodium chloride resulted in higher oil recovery than calcium chloride at a certain salinity in both imbibition and core flooding tests. The oil recovery factor results during the second water flooding cycle (after aging for 24 hrs.) showed more oil recovered during low salinity waterflooding. The stabilized inaction pressure was higher for CaCl2 than NaCl injection at certain flow rate and brine concentrations. Effluent pH values became more basic during low salinity water flooding for both sodium and calcium chloride. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 hours. Results also imply Low- salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency.
- North America > United States > California (0.46)
- North America > United States > Oklahoma (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
Successful Field Application of Microgel Treatment in High Temperature High Salinity Reservoir in China
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
Abstract This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs. Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
- Asia > China (1.00)
- North America > United States > Oklahoma (0.28)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Jilin > Yanji Basin > Jilin Field (0.99)
- Asia > China > Henan > North China Basin > Zhongyuan Field (0.99)
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