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A versatile and simple strategy is proposed to design CO2-responsive self-healable hydrogels based on hydrophobically-modified polymers bridged by worm like micelles.

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CO₂-responsive smart fluids have been widely investigated in the past decade. In this article, we reported a CO₂-responsive smart fluid based on supramolecular assembly structures varying from vesicles to wormlike micelles.

A polymer, β-MEA, was synthesised from β-cyclodextrin (β-CD), 3-chloro-2-methylpropene (MAC), epoxysuccinic acid (ESA), and 2-acrylamido-2-methyl propane sulfonic acid (AMPS) with a (NH4)2S2O8-NaHSO3 redox initiator system by aqueous solution radical polymerisation. β-MEA was characterised by means of IR spectroscopy, time-of-flight mass spectrometry, gel permeation chromatography, and thermogravimetric analysis. Its structure, molecular weight, thermal stability, scale and corrosion inhibition performance and mechanism were investigated. The results verified that β-MEA achieves a better scale inhibition efficiency for BaSO4 compared with poly(aspartic acid) (PASP) (100 % cf. 94.9 % at a concentration of 20 mg L−1) and a better corrosion inhibition efficiency of N80 carbon steel in saline water compared with PESA (91.2 % cf. 79.7 % at a concentration of 1 g L−1). The BaSO4 was characterised by scanning electron microscopy (SEM) and X-ray diffraction to investigate the crystal morphology of the scale. Primary research on the mechanism for corrosion inhibition was carried by SEM-chemical analysis.

Injectable self‐healing hydrogels have found broad applications in drug delivery, tissue engineering and controlled 3D cell culture. In this article, the coordination interaction between polymer‐bearing imidazole groups and Mg2+ ions “trapped” in Laponite, has been employed to develop an injectable self‐healing nanocomposite hydrogel. The properties and gelation mechanism of the hydrogel have been characterized and demonstrated by rheology, TEM, XRD, SEM, and NMR in particular. The hydrogel exhibits swift self‐healing performance without waiting for long time or elevated temperature. In particular, the present hydrogel can be applied in harsh alkaline environments, exhibiting a great advantage over traditional metal ion crosslinked hydrogels. The injectable self‐healing hydrogels based on the coordination interaction between Laponite and polymer have been rarely reported. Our research may make contributions not only to the design but also to the potential application of the hydrogels in a range of harsh alkaline environments, especially in enhanced oil recovery (EOR).

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In order to compensate formation pressure and maintain oil production, a carbonate oilfield in the Middle East adopts water flood development. The injected water exhibits the feature of high salinity and high content of chloride, high content of H2S, and high content of scaling ion. As a result, severe corrosion perforation and plugging were encountered in less than two years, which seriously affects the normal water injection and production of the oilfield. This paper aims to find out the main controlling factors and co-evolution law of corrosion and scaling, and propose the prevention strategy. The composition of the scale samples is firstly analyzed by combustion method, XRD and atomic absorption spectrometry, and then the main controlling factors of corrosion and scaling are experimentally clarified. On this basis, immersion experiments at different times are further carried out to reveal the evolution of corrosion and scaling in injectors at different depths. The results show that temperature, salinity (mainly Cl-), total sulfur content, and sulfate reducing bacteria (SRB) are the main factors controlling corrosion and scaling, and there is a synergistic effect among them. Temperature and sulfide have a promoting effect on uniform corrosion and scaling, while the salinity in the range of 110g/L-180g/L has an inhibition effect, but has a promoting effect on localized corrosion under deposits; a small amount of SRB can still propagate rapidly under deposits, aggravating the localized corrosion. Along the wellbore profile from top to bottom, the uniform corrosion rate and scaling amount increase but the localized corrosion rate decreases, which indicates that the high risk of localized corrosion perforation in the middle and upper part of the wellbore, as compared to the lower part. It is consistent with the actual corrosion perforation law of water injection wells. The co-evolution mechanism of corrosion and scaling is a synergistic process of three factors: lower uniform corrosion rate under high salinity + sulfide-induced local corrosion initiation + SRB enrichment under deposits and acidification autocatalysis due to Cl- migration. Finally, corrosion and scale control measures were taken by deep desulfurization and adding corrosion inhibitor. This work provides useful practical experience for preventing corrosion and scale formation of high salinity injector in carbonate oilfield.