Abstract
Inter-salt shale oil reservoirs located between two salt layers are always accompanied by high temperature and high salinity. However, the present commonly used water-soluble polymers in fracturing fluids suffer from poor tolerance to high temperature and high salinity. Thermoviscosifying polymers (TVP) whose aqueous solution shows viscosity increase upon increasing temperature and salt concentration have received considerable attention recently, which is promising for utilization in fracturing fluids to overcome these problems. In this work, both the salt-induced viscosifying property and mechanism of a TVP solution were investigated and the performance of TVP used as fracturing fluid based on the conditions of the Jianghan inter-salt shale oil reservoir in China was evaluated. It is found that the salt-induced viscosifying property of the TVP solution decreases with temperature and shear rate, but increases with polymer concentration. The number of intermolecular hydrophobic domains increases with the salt concentration contributing to the strengthening of a 3D network structure, which results in an increase in viscosity. In addition, the TVP fracturing fluid formulated with saturated brine exhibits excellent temperature and shear resistance, sand-suspending performance, and gel-breaking performance. Its viscosity remains above 50 mPa s after being sheared for 1 h even at a high temperature of 140 °C and the sand-suspending stability can be maintained for more than 1 week at 100 °C. Furthermore, the fracturing fluid can be easily broken down within 12 h using 0.2 wt%–0.3 wt% potassium persulfate without residue.
Highlights
Shale oil and gas have been considered to be the most promising unconventional alternative energy resources in the future according to the exploration and production history in North America (Soeder 2018)
In consideration of the temperature and salinity doubly induced viscosifying ability of Thermoviscosifying polymers (TVP), for the first time we proposed the idea of applying TVP to solve the fracturing problem in the inter-salt shale oil reservoirs with high-temperature and high-salinity (HTHS)
To avoid the disturbance of temperature when discussing the influence of shear rate on salt-induced viscosifying effect, the temperature was kept at 30 °C during which the apparent viscosity of TVP in different salinity brine was measured with increasing shear rates
Summary
Shale oil and gas have been considered to be the most promising unconventional alternative energy resources in the future according to the exploration and production history in North America (Soeder 2018). They proved the effectiveness of hydrophobic associative polymers for hydraulic fracturing applications at high temperatures (up to 190 °C) in conventional brines (2000–4000 ppm) without the addition of external cross-linkers, and found a preliminary encouraging cleanup profile during gel breaking Those physically cross-linked fracturing fluids seem not as salt tolerant and no research has focused on their performance in high salinity or saturated brine. What should be pointed out is that a solution of low polymer concentration with over 10 wt% NaCl still has the thermoviscosifying effect of this TVP, and more interestingly, the viscosity of TVP solution in high-salinity brine is always higher than that in low-salinity brine in the whole temperature range from 20 to 90 °C (Li et al 2017) This outstanding salt-thickening ability of the TVP has attracted our keen interest in explaining its salt-induced viscosifying mechanism, and exploring its application in high-salinity reservoirs, such as the Jianghan inter-salt shale oil reservoir. The rheological behavior of this TVP was presented in different brines with salinity increasing from zero to saturation and its salt-induced viscosifying mechanism was discussed
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