Supercritical carbon dioxide (SC-CO2) fracturing has been used in developing low permeability and water-sensitive reservoirs in recent years, which is expected to become a new generation of unconventional reservoir fracturing fluid. However, the water-rock interaction characteristics of various lithology shales under SC-CO2 circumstance and its influence on fracturing effect still need to be investigated. Two kinds of shale samples from C7 and S1 formations of the Ordos Basin were treated by SC-CO2 with formation water. The aims of the research are to determine the processes taking place in shale reservoir when considering minerals components transformation, porosity/permeability variation, and micro pore-structure change during the SC-CO2 fracturing. Static and dynamic SC-CO2 immersed experiments were conducted and the scanning of electron microscopy (SEM) and X-ray diffraction (XRD) was employed to analyze the surface morphology and newly formed minerals. Helium porosimeter, the ultralow permeability meter, and the CT scanner are employed to record the alternation of physical parameters during SC-CO2 dynamic injection. The experimental results show that the C7 samples are rich of chlorite and easily reacting with SC-CO2 saturated formation water to form new minerals, but the S1 samples are insensitive to aqueous SC-CO2. The minimum value of permeability and porosity of the C7 cores appear at 24 h in the long-interval experiment, but in the short-interval dynamic experiment, the minimum values move ahead to 12h. The optimal flowback time for the C7 reservoir is before 12 h or after 24 h. The high-pressure SC-CO2 flooding pushes the new forming minerals particles to migrate to the outlet side and block the pore throat. For the S1 core results, the porosity and permeability change little in both short and long interval experiments. There is no strict flow-back time requirement for S1 reservoir during SC-CO2 fracturing. This study is significance for the efficient application of SC-CO2 in the exploitation of shale oil reservoirs.

Underground gas storage is characterized by large gas injection and withdrawal cycles, making the wellbore bear repeated loading and unloading. Subjecting cement sheath to these conditions can cause damage, thus compromising its ability to provide complete zonal isolation. Wellbore annulus plugging with high-strength resin technology was studied to evaluate its effectiveness in controlling unwanted fluid migration through triaxial mechanical properties test, corrosion inhibiting ability test, and anti-gas channeling performance evaluation. The experimental results showed that the curing time was extended by 1.9 hrs by doubling the amount of diluent. At the same time, doubling the amount of the curing agent increased the compressive strength by 5.3 MPa. Under the triaxial test conditions, the four resin materials exhibited high compressive strength, low elastic modulus, and low Poisson’s ratio. Injection of corrosive CO2 at 0.5 MPa, reduced the compressive strength of the four resins within the range of 4.9% ~24.3%. A 100g of epoxy resin mixed with 10 g of diluent and 20 g of the curing agent significantly reduced the curing time. In addition, this mixture increased the maximum differential stress, and elastic modulus to 100.5 MPa and 3.325 GPa, respectively, after 1.6 h. The gas test anti-channeling pressure of the 5 cm sample was as high as 19.1 MPa. The test samples maintained long-term stability under continuous high pressure and tightness under the action of the alternating load of a significant pressure difference. This study uses high-strength plugging gel technology to provide a technical guide for wellbore remedial redress and plugging in underground gas storage.

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