With increasing global energy consumption, oil/gas drilling has gradually expanded from conventional shallow reservoirs to deep and ultra-deep reservoirs. However, the harsh geological features including high temperature and high salinity in ultra-deep reservoirs have become a critical challenge faced by water-based drilling fluids (WDFs), which seriously deteriorate the rheology and fluid loss properties, causing drilling accidents, such as wellbore instability and formation collapse. In this study, a novel temperature- and salt-resistant micro-crosslinked polyampholyte gel was synthesized using N,N-dimethylacrylamide, diallyldimethyl ammonium chloride, 2-acrylamido-2-methylpropanesulfonic acid, maleic anhydride and chemical crosslinking agent triallylamine through free radical copolymerization. Due to the synergistic effect of covalent micro-crosslinking and the reverse polyelectrolyte effect of amphoteric polymers, the copolymer-based drilling fluids exhibit outstanding rheological and filtration properties even after aging at high temperatures (up to 200 °C) and high salinity (saturated salt) environments. In addition, the zeta potential and particle size distribution of copolymer-based drilling fluids further confirmed that the copolymer can greatly improve the stability of the base fluid suspension, which is important for reducing the fluid-loss volume of WDFs. Therefore, this work will point out a new direction for the development of temperature- and salt-resistant drilling fluid treatment agents.

In view of challenges such as the long dissolution time of powder friction reducers in high-salinity water, poor environmental friendliness of water-in-oil (W/O) emulsion friction reducers, and the poor proppant-carrying capacity of conventional slickwater, a novel variable viscosity friction reducer suspension (EACM) with high salt tolerance, low damage, and strong proppant-carrying capacity was prepared by dispersing salt-tolerant polymer powder in alcohol solvents. The solubility, drag reduction ability, viscoelasticity, proppant-carrying capacity, temperature and shear resistance, and gel breaking ability of EACM were investigated. The results showed that the best solvent for the friction reducer suspension was polyethylene glycol 400, in which EACM exhibited a rapid dissolution rate with a thickening rate of 89.5% within 2 min. Due to the synergic effect between fumed silica and polyamide wax as antisedimentation agents, both at a concentration of 2.0 wt %, the EACM could remain stable for 60 days. EACM showed an excellent drag reduction performance at both low and high viscosities in 100 000 mg/L salt brine. Specifically, a drag reduction of up to 72.4% was obtained using 0.21 wt % EACM (4.65 mPa s), and a 60.8% drag reduction was achieved using 1.0 wt % EACM (35.5 mPa s). When the concentration increased from 0.13 to 1.0 wt %, the EACM solution changed from viscous to elastic; the spatial network structure of the solution became more compact, and the proppant-carrying capacity was enhanced. The viscosity of 1.6 wt % EACM solution could be maintained at 55.9 mPa s after shearing at 90 °C for 120 min at a shear rate of 100 s −1 . EACM solution also exhibited the advantages of easy breaking and low residue. This paper provides guidance for the design and selection of a novel friction reducer suspension in the oil and gas industry.

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Colloidal Gas Aphron as a mobility control in enhanced oil recovery is becoming attractive; it is also designed to block porous media with micro-bubbles. In this paper, the effects of surfactant concentration, polymer concentration, temperature and salinity on the bubble size of the Colloidal Gas Aphron were studied. Effects of injection rates, Colloidal Gas Aphron fluid composition, heterogeneity of reservoir on the resistance to the flow of Colloidal Gas Aphron fluid through porous media were investigated. Effects of Colloidal Gas Aphron fluid composition and temperature on residual oil recovery were also studied. The results showed that bubble growth rate decreased with increasing surfactant concentration, polymer concentration, and decreasing temperature, while it decreased and then increased slightly with increasing salinity. The obvious increase of injection pressure was observed as more Colloidal Gas Aphron fluid was injected, indicating that Colloidal Gas Aphron could block the pore media effectively. The effectiveness of the best blend obtained through homogeneous sandpack flood tests was modestly improved in the heterogeneous sandpack. The tertiary oil recovery increased 26.8 % by Colloidal Gas Aphron fluid as compared to 20.3 % by XG solution when chemical solution of 1 PV was injected into the sandpack. The maximum injected pressure of Colloidal Gas Aphron fluid was about three times that of the XG solution. As the temperature increased, the Colloidal Gas Aphron fluid became less stable; the maximum injection pressure and tertiary oil recovery of Colloidal Gas Aphron fluid decreased.