The movability of water in shale nanopores intensely affects the transport and storage of other fluids, and plays an important role in the geological water cycle. To investigate the movability, three shale samples were used to conduct flow experiments using the “steady‐state and step‐by‐step depressurization” method. The experimental results show that the movability of water strongly depends on the pressure gradient. Two water‐related mechanisms, “shear fluidity” and “electro‐viscous effect”, are primarily responsible for the difference in movability between the free water and bound water. The flow of water in these samples deviates from Darcy’s law, and the threshold pressure gradient (TPG) is observed. When the pressure gradient is higher than the TPG, water starts to flow, and the permeability increases with increasing pressure gradient. Based on the analysis of the solid‐liquid interfacial forces, the water in the shale was quantitatively classified into four types (L1 , L2 , L3 and L4 ) according to its movability. The calculation results indicate that most of the water, which could be up to 74.46%~89.73%, is immovable under the experimental conditions. The proportion of movable water increases with increasing pressure gradient, and the relation can be expressed by a quadratic function. The moving ratio was defined as the ratio of the volume of water involved in flow to the total pore volume. The correlation between the moving ratio and permeability is a power function with exponents ranging from 1.16 to 1.43, indicating that the water permeability is sensitive to the moving ratio.

Identifying the fate of contaminants (such as barium) during gas field produced water reinjection could be a feasible method to evaluate the environmental risks of the reinjection project and thus improve its sustainability. To assess the barium sorption behaviors during gas field produced water reinjected into sandstone reservoirs, a series of water–rock interactions experiments were conducted to systematically investigate the effects of brine/rock ratio (5:1~500:1), pH (3~10), temperature (20, 50 and 80 °C), brine salinity (NaCl solution, 0~100 g/L), competitive cations (Sr and Mg, 0.5 g/L), and organic compound (methanol, 0~5 g/L) on the sorption of barium in sandstone. The rock samples were collected from the Triassic formation of the Yanchang Group in the northern Ordos Basin, China. The results indicated that the sorption of barium in sandstone strongly depends on the brine/rock ratio. Under the same brine/rock ratio, the severity of the impact on the barium sorption from high to low was competitive cation, salinity, pH, temperature, and methanol concentration. The sorption process of barium onto the sandstone could be well fitted by a pseudo-second-order kinetics model. The presence of competitive cations would restrain the sorption of barium, while the existence of methanol hardly affects the barium sorption. The chloro-complexation reaction and the reduction of rock surface electrical potential are mainly responsible for the inhibition effects of NaCl salinity on barium sorption, and the corresponding relationship can be characterized by an exponential function. Barium sorption in sandstone decreases with increasing temperature, while it is positively correlated to the initial pH of the solution. The water-rock system is weakly alkaline with a value of 7.7–8.5 when the barium sorption reaches an equilibrium state, regardless of the initial pH of the reactive solution. The results are meaningful in understanding and predicting the fate of barium after the gas field produced water was reinjected into the underground.

The permeability of shale is a controlling factor in fluid migration, solute transport, and overpressure development in a sedimentary basin. However, shale permeabilities measured with different fluids can be very different. To investigate the effects of fluid type on shale liquid permeability, a series of flow experiments on three samples were conducted using deionized water, liquid CO2 and 1 mol/L NaCl solution as permeating fluids. The results indicate that the liquid CO2 flow obeys Darcy’s law, showing a constant permeability. The liquid CO2 permeabilities of samples C01, C02 and C03 are 6.90×10-19 m2, 3.80×10-20 m2 and 1.59×10-18 m2, respectively. The transport of the deionized water and NaCl solution in these samples deviates from Darcy’s law, and threshold pressure gradient is observed. The permeabilities measured with these two fluids exhibit nearly identical ranges (10-20~10-21 m2). The sample permeated with NaCl solution generally shows a lower permeability (under the same pressure gradient) but a higher threshold pressure gradient. The relationship between water permeability and pressure gradient follows a power function, with exponents ranging from 0.96~3.41 for deionized water and 0.34~3.30 for NaCl solution. The permeability reduction magnitude (ω) was defined to describe the difference between the three liquid permeabilities and the helium absolute permeability. The range of ω is 0.25~0.96 for liquid CO2, 1.44~2.32 for deionized water and 1.89~3.09 for NaCl solution. The dependence of permeability on fluid type results from the differences in the fluid properties (viscosity and polarity) and fluid-mineral interactions.