Triaxial testing on water permeability evolution of fractured shale

A sound understanding of the water permeability evolution in fractured shale is essential to the optimal hydraulic fracturing (reservoir stimulation) strategies. We have measured the water permeability of six fractured shale samples from Qiongzhusi Formation in southwest China at various pressure and stress conditions. Results showed that the average uniaxial compressive strength (UCS) and average tensile strength of the Qiongzhusi shale samples were 106.3 and 10.131 MPa, respectively. The nanometre-sized (tiny) pore structure is the dominant characteristic of the Qiongzhusi shale. Following this, we proposed a pre-stressing strategy for creating fractures in shale for permeability measurement and its validity was evaluated by CT scanning. Shale water permeability increased with pressure differential. While shale water permeability declined with increasing effective stress, such effect dropped significantly as the effective stress continues to increase. Interestingly, shale permeability increased with pressure when the pressure is relatively low (less than 4 MPa), which is inconsistent with the classic Darcy's theory. This is caused by the Bingham flow that often occurs in tiny pores. Most importantly, the proposed permeability model would fully capture the experimental data with reasonable accuracy in a wide range of stresses.

Evolution of the Oil Shale Permeability under Real-Time High-Temperature Triaxial Stress in the Jimusar Area, Xinjiang

This paper adopts a real-time high-temperature triaxial seepage test system to study the permeability evolution of oil shale in the Jimusar area, Xinjiang, with the temperature, pore pressure, and volumetric stress. The results indicate that (1) the variation process of the oil shale permeability with the temperature can be divided into three stages: slow growth stage from 20 to 350°C, rapid growth stage from 350 to 500°C with a threshold temperature of 400°C, and growth deceleration stage from 500 to 600°C. (2) With increasing pore pressure, the permeability gradually decreases. Under a volumetric stress of 17 MPa, the permeability decreases the most rapidly from 1 to 2 MPa, and under a volumetric stress of 34 MPa, the permeability decreases the fastest from 1 to 3 MPa. (3) The oil shale permeability decreases with increasing volumetric stress. At room temperature, the decrease magnitude of the permeability is small and increases with increasing temperature. The results can provide a theoretical reference for the analysis of the seepage process of thermal fluids and pyrolysis oil and gas in oil shale.

Investigation of Shale Permeability Evolution considering Bivalued Effective Stress Coefficients for CO2 Injection

Because of the existence of multiscale pores from nano- to macroscale, a multimechanistic shale gas flow process involving the Darcy and Knudsen flows occurs during gas shale well depletion. The respective contribution of the Darcy and Knudsen flows to the permeability is constantly changing with pressure evolution. In this study, laboratory measurements of shale permeability with CO2 injections were carried out under hydrostatic conditions, using the transient pulse-decay method. The “U”-shape permeability curve resulted in both positive and negative effective stress coefficients (Biot’s coefficient) χ . A permeability turning point was thus created to partition permeability curves into the Darcy and Knudsen sections. The Knudsen effect was proven to be significant at low pressure/late time in the laboratory. Effective stress and sorption-induced deformation have been found to govern the Darcy permeability evolution under the tested experimental conditions. Thus, negative effective stress coefficients, together with the positive ones, should be applied to a nonmonotonic pressure-permeability evolution to explain the concurrent effect of the Darcy flow and Knudsen flow at different pore pressures.

Shale Permeability under Shale Components’ Thermal Swelling

Permeability is one of the most fundamental reservoir rock properties required for modeling hydrocarbon production. However, shale permeability is not yet fully understood because of the high temperature of shale reservoirs. The third thermal stress that is caused by temperature change will decrease the permeability of shale. In this work, a theoretical model has been derived to describe the permeability of shale considering the third thermal stress; the principles of thermodynamics and the mechanics of elasticity have been employed to develop this model. The elastic modulus parameters of the shale were measured, along with Poisson’s ratio, as required. Lastly, the permeability of shale was tested by transient pulse-decay. Isothermal flow experiments were carried out at 303, 313, 323, and 333 K to assess the effects of shale expansion and deformation on shale permeability caused by the third thermal stress. The permeability of shale samples, as predicted by the model, was found to agree well with experimental observations. The model may provide useful descriptions of the gas flow in shale. The correction accuracy of the permeability was found to increase at lower permeability. However, the development of completely predictive models for shale permeability will require additional experimental data and further testing.

Fractal characteristics of shale pore structure and its influence on seepage flow

The migration law of shale gas has a significant influence on the seepage characteristics of shale, and the flow of the gas is closely related to the pore structure. To explore the influence of shale pore parameters on permeability in different diffusion zones, the pore structure of the shale in the Niutitang Formation in Guizhou, China, was analysed based on liquid nitrogen adsorption experiments and nuclear magnetic resonance experiments. The relationship among fractal dimension, organic carbon content (TOC) and BET-specific surface area was analysed based on the fractal dimension of shale pores calculated using the Frenkel–Halsey–Hill model. Shale permeability was calculated using the Knudsen number ( Kn ) and permeability equation, and the influence of the fractal dimension and porosity in different diffusion zones on shale permeability was analysed. Previous studies have shown that: (i) the pores of shale in the Niutitang Formation, Guizhou are mainly distributed within 1–100 nm, with a small total pore volume per unit mass, average pore diameter, large BET specific surface area and porosity; (ii) fractal dimension has a negative correlation with average pore diameter and TOC content and a quadratic relationship with BET specific surface area; and (iii) permeability has a positive correlation with Kn , porosity and fractal dimension. In the transitional diffusion zone, fractal dimension and porosity have a significant impact on permeability. In the Knudsen diffusion zone, porosity has no obvious effect on permeability. The methodologies and results presented will enable more accurate characterization of the complexity of pore structures of porous media and allow further understanding of the seepage law of shale gas.

Study on mechanism of spontaneous imbibition and pressurized imbibition in shale oil reservoirs

Imbibition is one of the important methods of oil recovery in shale oil reservoirs. At present, more in-depth studies have been carried out on the fracture system and matrix system, and there are few studies on the effect of energy enhancement on imbibition in shale oil reservoirs. Therefore, based on the study of pressurized imbibition and spontaneous imbibition of shale oil reservoirs in Qianjiang Sag, Jianghan Basin, nuclear magnetic resonance technology was used to quantitatively characterize the production degree of shale and pore recovery contribution under different imbibition modes, and analyze the imbibition mechanism of shale oil reservoirs under the condition of energy enhancement. The experimental results showed that with the increase in shale permeability, the recovery ratio of pressurized imbibition also increased. The rate of pressurized imbibition was higher than spontaneous imbibition, and pressurized imbibition can increase the recovery ratio of fractured shale. Spontaneous imbibition can improve the ultimate recovery ratio of matrix shale. Pressurized imbibition can increase the recovery contribution of macroporous and mesoporous.