Search

Abstract Using surfactants to extract oil, the anionic surfactant Karamay petroleum sulfonate (KPS), the zwitterionic surfactant octadecyl betaine (BS-18) and the nonionic surfactant coconut oil fatty acid diethanolamide (6501) were selected for adsorption experiments with minerals contained in the conglomerate reservoir with different mineral compositions to study the adsorption law of different types of surfactants. Zeolite and montmorillonite, which have the highest specific surface area and zeta potential among the minerals in the conglomerate reservoir, have the most obvious adsorption effect on surfactants, resulting in a large amount of adsorption of KPS and BS-18. The three types of surfactants were then used to conduct physical simulation oil recovery experiments with conglomerate core samples, and the results showed that 6501 had better overall performance, the best adsorption resistance, and a higher degree of recovery in oil recovery experiments, which provided a basis for the selection of surfactants in the process of chemical drive in conglomerate reservoirs.

Unconventional reservoirs are normally characterized by dual porous media, which has both multi-scale pore and fracture structures, such as low permeability or tight oil reservoirs. The seepage characteristics of such reservoirs is mainly determined by micro-fractures, but conventional laboratory experimental methods are difficult to measure it, which is attribute to the dynamic cracking of these micro-fractures. The emerging digital core technology in recent years can solve this problem by developing an accurate pore network model and a rational simulation approach. In this study, a novel pore-fracture dual network model was established based on percolation theory. Fluid flow in the pore of two scales, micro-fracture and matrix pore, were considered, also with the impact of micro-fracture opening and closing during flow. Some seepage characteristic parameters, such as fluid saturations, capillary pressure, relative permeabilities, displacement efficiency in different flow stage, can be predicted by proposed calculating method. Through these work, seepage characteristics of dual porous media can be achieved.

To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer (SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil recovery of SP flooding was investigated at the pore, core and field scales through conducting experiments on natural core samples with three typical types of pore structures. First, the in-situ nuclear magnetic resonance core flooding test was carried out to capture the remaining oil variation features in the water flooding and SP flooding through these three types of cores. Subsequently, at the core scale, displacement characteristics and performances of water flooding and SP flooding in these three types of cores were evaluated based on the full-size core flooding tests. Finally, at the field scale, production characteristics of SP flooding in the bimodal sandstone reservoir and multimodal conglomerate reservoir were compared using the actual field production data. The results show: as the pore structure gets more and more complex, the water flooding performance gets poorer, but the incremental recovery factor by SP flooding gets higher; the SP flooding can enhance the producing degree of oil in 1–3 μm pores in the unimodal and bimodal core samples, while it produces largely oil in medium and large pores more than 3 μm in pore radius in the multimodal core sample. The core flooding test using full-size core sample demonstrates that the injection of SP solution can significantly raise up the displacement pressure of the multimodal core sample, and greatly enhance recovery factor by emulsifying the remaining oil and enlarging swept volume. Compared with the sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. With proper profile control treatments to efficiently enlarge the microscopic and macroscopic swept volumes, SP flooding in the conglomerate reservoir can contribute to lower water cuts and longer effective durations. Key words: conglomerate reservoir, pore structure, surfactant/polymer flooding, displacement effect, oil recovery enhancement

Accurately predicting the solubility of elemental sulfur in sour gas mixtures is a primary task. As a current and widely-used model on the solubility of elemental sulfur in sour gas mixtures, Chrastil's association model has a big error in the process of predicting experimental data based on different fitting methods. This paper combined with experimental data reported by relevant scholars about elemental sulfur solubility in sour gases and selected density, temperature and pressure as three important influential factors. According to different fitting methods, we can calculate the correlation parameters in Chrastil's model. Then different solubility formulas can be used to predict the solubility of elemental sulfur in sour gas mixtures. Through in-depth research and analysis of Chrastil's solubility model from numerical aspects, it's easy to find the irrationality about Chrastil's solubility model and fitting methods. Especially in fitting methods, further improvement of the fitting method is proposed and used to predict the solubility of elemental sulfur in sour gas mixtures. The calculation results show that some improvements of the predicting precision have been achieved by using the improved fitting method in Chrastil's association model.