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Degradation of phoxim in river water was fully explored in this paper. Effects of pH, temperature, and photoirradiation on the degradation were investigated in detail. The results indicated that the degradation was characterized by a first-order process; UV irradiation and the increase of pH and temperature substantially accelerated the degradation. To fully characterize the degradation mechanism, HPLC-MS/MS was utilized to identify the degradation intermediates. Five intermediates were identified as phoxom, phoxom dimer, O,O,O',O'-tetraethyldithiopyrophosphate, O,O,O'-triethyl-O'-2-hydroxyethyldisulfinylpyrophosphate, and O,O,O'-triethyl-O'-2-hydroxyethyldithiopyrophosphate. On the basis of the results of the intermediate analysis, the degradation pathways of phoxim under the present experimental conditions were proposed. Through conversion of a thiophosphoryl into a phosphoryl group, some phoxim was converted to phoxom, most of which further formed dimer. Another portion of phoxim transformed to O,O,O',O'-tetraethyldithiopyrophosphate via nucleophilic substitution and photolysis. Thereafter, O,O,O',O'-tetraethyldithiopyrophosphate underwent hydroxylation to form O,O,O'-triethyl-O'-2-hydroxyethyldithiopyrophosphate or sulfur oxidation first and then hydroxylation to produce O,O,O'-triethyl-O'-2-hydroxyethyldisulfinylpyrophosphate. The understanding of phoxim's degradation mechanism in this study will be critical to its safety assessment and increase the understanding of the fate of phoxim in environment water.

Injecting carbon dioxide (CO2) as foam during enhanced oil recovery (EOR) can improve injectate mobility and increase sweep efficiency. Integrating CO2-foam techniques with carbon capture, utilization and storage (CCUS) operations is of recent interest, as the mobility control and sweep efficiency increases seen in EOR could also benefit CO2 storage during CCUS. In this study, a variety of different charge, hydrocarbon chain length, head group surfactants were evaluated by surface tension, bulk and dynamic CO2-foam performance assessments for CCUS. The optimal foam candidate was expected to provide satisfying mobility control effects under reservoir conditions, leading to an improved water displacement efficiency during CO2-foam flooding that favors a more significant CO2 storage potential. All tested surfactants were able to lower their surface tensions against scCO2 by 4-5 times, enlarging the surface area of solution/gas contact; therefore, more CO2 could be trapped in the foam system. A zwitterionic surfactant was found to have slightly higher surface tension against CO2 while exhibiting the highest foaming ability and the most prolonged foam stability with a relatively slower drainage rate among all tested surfactants. The dynamic performance of scCO2-foam stabilized by this zwitterionic surfactant was also evaluated in sandstone and carbonate cores at 13.79 MPa and 90°C. The results show that the mobility control development in carbonate core was relatively slower, suggesting a gradual foam generation process attributed to the higher permeability than the case in sandstone core. A more significant cumulative CO2 storage potential improvement, quantified based on the water production, was recorded in sandstone (53%) over the carbonate (47%). Overall, the selected foam has successfully developed CO2 mobility control and improved water displacement in the occurrence of in-situ foam generation, hence promoting the storage capacity for the injected CO2. This work has optimized the foaming agent selection method at the actual reservoir conditions and evaluated the scCO2-foam performance in establishing high flow resistance and improving the CO2 storage capacity, which benefits integrated CCUS studies or projects utilizing CO2-foam techniques.

Foam flooding has been used for gas conformance control during enhanced oil recovery (EOR) in heterogeneous reservoirs. The application of foam flooding in naturally or hydraulically fractured reservoirs has recently been gaining attention. There are, however, limited studies on supercritical CO 2 (scCO 2 ) foam behavior in the fractured system. Specifically, the impact of fracture properties such as aperture size, surface roughness, and fracture orientation in natural rocks are not well studied. In this work, we investigated the behavior of scCO 2 foam stabilized by a viscoelastic surfactant in fractured systems. The apparent viscosity of foam in fractured and nonfractured cores was compared. Furthermore, the effects of fracture surface roughness and crude oil on foam behavior were determined. We found that the fracture surface roughness positively affects the apparent viscosity of foam in the absence and presence of crude oil. Also, the formation of the complex structure of the water-oil-CO 2 system during oil−foam co-injection may serve a major role in causing a significant apparent viscosity.