The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.

Generally, huge amounts of fracturing fluid are used in a shale gas well but the flowback efficiency is low. Since the distribution characteristics of imbibed fracturing fluid in shale are complex, they need further evaluation. This paper takes the Longmaxi Shale as the research object, including matrix cores, natural fracture cores and cores of artificial fracture with proppant. Stress sensitivity experiments are carried out on the above three kinds of cores under different degrees of imbibition and retention state of fracturing fluid. The results show that when the degree of aqueous phase retention is 0-0.78 pore volume, water mainly appears in the pores with a diameter of 2-50 nm. As the water saturation increases to more than 0.9 pore volume, the amounts of aqueous phase in the pores or fractures with a hydraulic diameter of 100-1,000 nm and larger than 1,000 nm increase significantly. Both the stress sensitivity of nanopores and natural fractures are enhanced by aqueous phase retention. With the increase in effective stress, the permeability damage rate of artificial fracture cores with proppant is inversely proportional to the degree of fracturing fluid retention. Aqueous phase retention in the pores with a diameter of 2-50 nm significantly contributes to the stress sensitivity of matrix cores. With the increase in effective stress, aqueous phase retention in pores with diameter larger than 100 nm increases the stress sensitivity of natural fracture cores. It is recommended that the retention degree of fracturing fluid in a shale gas reservoir should be controlled below 0.5 pore volume. In this case, the stress sensitivity of natural fractures will be less aggravated by fracturing fluid retention, and the stress sensitivity of artificial fracture with proppant will be reduced to a certain extent.

Hydraulic fracturing of shale gas reservoirs is characterized by large fracturing fluid consumption, long working cycle and low flowback efficiency. Huge amounts of fracturing fluid retained in shale reservoirs for a long time would definitely cause formation damage and reduce the gas production efficiency. In this work, a pressure decay method was conducted in order to measure the amount of fracturing fluid imbibition and sample permeability under the conditions of formation temperature, pressure and adsorbed methane in real time. Experimental results show that (1) the mass of imbibed fracturing fluid per unit mass of shale sample is 0.00021–0.00439 g/g considering the in-situ pressure, temperature and adsorbed methane. (2) The imbibition and flowback behavior of fracturing fluid are affected by the imbibition or flowback pressure difference, pore structure, pore surface properties, mechanical properties of shale and mineral contents. (3) 0.01 mD and 0.001 mD are the critical initial permeability of shales, which could be used to determine the relationship between the formation damage degree and the flowback pressure difference. This work is beneficial for a real experimental evaluation of shale formation damage induced by fracturing fluid.