This work presents a novel treatment for mitigating the condensate damage and improving the reservoir productivity using thermochemical fluids. Experimental measurements and numerical simulation were carried out. The experimental measurements include kinetic reaction, coreflooding experiments, NMR (nuclear magnetic resonance) and capillary pressure measurements. The used rock samples (shale, sandstone, and carbonate) were characterized using NMR and routine core analysis. Moreover, numerical simulation was conducted using CMG software. Field scale simulation was conducted to evaluate the effectiveness of thermochemical treatment in increasing the ultimate gas recovery from tight gas reservoir. Results showed that thermochemical treatment can mitigate the condensate damage by around 60%, decrease the capillary forces by 55% and increase the absolute open flow up to 450%. Permeability and NMR measurements showed that multiple fractures were induced after the treatment, the absolute permeability increase by more than 200 times. Furthermore, the field scale simulation showed that thermochemical treatment can increase the ultimate gas recovery up to 89.1% compared to 25.3% using cyclic gas injection, at same conditions. Ultimately, this work can lay the foundation for real field application of thermochemical treatment.


Natural gas reservoirs are main sources of energy around the world, due to its clean energy and low price (BP, 2013; Hassan et al., 2019). However, several problems can encounter the production from these sources, especially for tight reservoir where the rock permeability is extremely low, and the capillary forces is significantly high (Economides et al., 1989; Al-Anazi et al., 2002; Marokane et al., 2002; Restrepo et al., 2012; Sayed and Al-Muntasheri, 2016). One of the critical problems in tight reservoirs is the condensate banking (Al-Anazi et al., 2002; Sayed and Al-Muntasheri, 2016; Hassan et al., 2019). During the production, the reservoir pressure declines isothermally till it reaches a point that located inside the two-phase envelope. Then, liquid starts accumulating around the wellbore and affect the hydrocarbon production (Muskat, 1949; Kniazeff and Naville, 1965; Economides et al., 1989; Novosad, 1996). At some situations, the accumulated liquids around the wellbore can lead to stop the gas production completely, and this phenomenon is called condensate blockage (Sayed and Al-Muntasheri, 2016; Sayed et al., 2018; Hassan et al., 2019). Generally, the radius of condensate banking depends mostly on formation pressure, hydrocarbon composition and the gas production rate. Higher gas production can lead to faster reservoir depletion and then quicker development of the condensate banking (Wilson, 2004; Bozorgzadeh and Gringarten, 2006).

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