Yuxuan Tian,Yaming Qi,Hongjing Han,Xinzhan Luo,Junyao Guan,Sijia Chen,Haiying Wang,Yanguang Chen,Xuzhong Gong
Tight oil is an important unconventional oil resource, but it is difficult to separate oil and water from produced liquid and make efficient use of it. Due to the stable structure of oil–water interface caused by resin, it is difficult to achieve demulsification. In this work, a series of polyether ester demulsifierswith different degree of polymerization were designed by esterification and polymerization. In addition, hydrogen peroxide was used to regulate the structure of resin to enhance the transmission of polyether ester, and the replacement of resin was strengthened through the structural design of polyether ester. The results showed that the molecular weight and dipole moment of resin oxidized by hydrogen peroxide decreased, which was beneficial to the transfer of demulsifier. With the increase of polymerization degree, the oil solubility and surface activity of polyether ester were improved, and the replacement ability of resin was strengthened·H 2 O 2 and demulsifier were used to synergistically promote demulsification, the dehydration rate could be further increased to 99.2%, and the water content in tight oil could be reduced to 0.56%.
Xu Ruifeng,Wang Shuoshi,Guo Ping,Hukuang Haoxiang,Yuan Na
The CO 2 -WAG injection method proposed for unconventional tight oil reservoirs has been successfully applied in field. However, for water-sensitive tight oil reservoirs, there is a lack of research focusing on the displacement mechanisms and effects of WAG injection at the pore scale. And the gap between nuclear magnetic resonance (NMR) and computerized tomography (CT) scanning technologies is not well explored. This study integrated deuterium oxide-shielded NMR and contrast agent (n-butane iodide and lead iso-octanoate mixture) enhanced micro-CT to study the immiscible CO 2 -WAG mechanisms for water-sensitive tight oil. The aim is to investigate the microscopic distribution and displacement mechanisms of residual oil after CO 2 flooding and WAG injection in water-sensitive cores. Experimental results showed that NMR experiments and CT experiments identified the microscopic distribution of oil at different injection stages successfully. The contrast agent, despite its similar viscosity ratio, had poor representativeness in other properties, leading to significant differences in the microscopic fluid distribution results compared to NMR experiments. The primary WAG flood mechanism observed was that CO 2 dispersed oil droplets, with most being displaced out of the pores, while water played a mobility control role by blocking large pores. However, due to water sensitivity, medium and small pores also experienced blockage, making the effect of WAG injection after CO 2 flooding not significant. In the NMR experiment, the final recovery of core 6–1 after WAG injection was 64.71%. In the CT scan experiment, due to the smaller volume of the microcore, the water sensitivity effect was relatively weaker, and under the stronger influence of the capillary end effect, the final recovery reached 76.91%. In the five sets of long-core experiments, by controlling the gas–water ratio and slug size, the recovery ranged from 56.51 to 64.04%. The core flood experiments validated the representativeness of the microscopic experiments. And for water-sensitive tight oil reservoirs, controlling the volumes of water and CO 2 during the WAG injection process is crucial.
Countercurrent imbibition of the fracturing fluid is of much significance for enhancing oil production in tight oil reservoirs during the shut-in period after hydraulic fracturing. The addition of enhanced imbibition agents such as surfactants and nanoparticles into the polymer-based fracturing fluid is conducive to oil production. How different types of imbibition agents affect oil recovery and the applicable conditions for different imbibition agents, however, still need to be clarified. In this article, we used low-field nuclear magnetic resonance (NMR) to measure the one-dimensional (1D) oil signal profiles along the imbibition direction during the countercurrent imbibition process and determine the imbibition distance and water saturation of different imbibition agents including polymer, surfactant, nano-silica (NS) and NS-surfactant complexes. Moreover, by measuring oil–water interfacial tension (IFT), and the adhesion forces between alkanes and the hydrophobic surfaces before/after the imbibition agent treatments by atomic force microscope (AFM), the IFT reduction and wettability alteration abilities of these agents were evaluated. After the NS-surfactant complexes treatment, the adhesion force which represents the force required to pull off oil from the rock surface became the lowest (15.81 pN), merely a quarter of that of NS (73.48 pN) and surfactant (70.01 pN), indicating a superior capability of NS-surfactant to improve wettability. The imbibition efficiency of the four systems in terms of imbibition distance and oil recovery was: NS-surfactant complexes: 38.43 mm 13.2 % > nonionic surfactant: 32.15 mm 9.0 % > NS: 25.88 mm 7.6 % > polymer: 17.64 mm 4.9 %. NS-surfactant nanofluid displayed the longest imbibition distance and highest water saturation, thus possessing the highest imbibition oil recovery. Nonionic surfactant with an IFT of 4.19 mN/m could greatly reduce the IFT compared with NS (35.98 mN/m), but the recovery enhancement induced by IFT reduction was not significant. In contrast, the increase in oil recovery by wettability alteration was distinctly higher than that by IFT reduction, as indicated by the recovery difference between NS-surfactant complexes and surfactant. Accordingly, wettability alteration is the primary mechanism to enhance imbibition oil recovery when ultralow IFT cannot be achieved. This research provides guidance on which type of imbibition agent should be selected to improve imbibition efficiency.
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