Large amounts of fracturing fluid retained in a shale reservoir could not only restrict gas production through aqueous phase trapping (APT) but also cause potential contamination of groundwater. In this work, experiments modeling in situ aqueous imbibition and flowback were conducted to quantitatively investigate the APT behavior in shales, including matrix, natural fracture, and artificial fracture. Results show that the forward imbibition process is slower than the reverse imbibition process. The aqueous phase tends to be imbibed through parallel bedding. Permeability reduction rates of matrix, natural fracture, and artificial fracture cores after imbibition could reach 100, 85, and 70%, respectively. Meanwhile, it is demonstrated that the aqueous flowback efficiency depends upon flowback timing, pressure difference, initial permeability, and bedding direction. The flowback efficiencies of matrix, natural fracture, and artificial fracture cores could be less than 7%, less than 30%, and less than 15%, respectively. Additionally, the permeability recovery rates of those could be less than 19%, less than 39%, and less than 67%, respectively. Finally, shale APT mechanisms are analyzed from both geological and engineering aspects. The quantitative investigation of shale APT is conducive to economically and environmentally developing shale gas reservoirs.
A large amount of fracturing fluid retained in a shale gas reservoir that does not flow back after hydraulic fracturing could induce formation damage of aqueous phase trapping (APT). A shale gas reservoir generally has a multiscale pore and fracture structure, so both retained fracturing fluid distribution and gas transport have multiscale characteristics. In this work, a comprehensive evaluation method of shale APT damage based on the analytic hierarchy process in fuzzy mathematics is put forward considering the petrophysical properties and multiscale gas transport behavior in a shale reservoir. First, the critical indexes of shale APT damage evaluation are determined. Then the hierarchy structure for APT damage evaluation for a shale gas reservoir is constructed. Finally, the weights of the critical evaluation indexes of shale APT damage are calculated on the basis of the analytic hierarchy process. Taking Longmaxi shale reservoir as an example, the APT damage degrees for matrix and fractures are calculated to be 65% and 84%, respectively. The evaluation method for shale APT damage proposed in this work is beneficial to accurately predicting the productivity of a shale gas well and optimizing the hydraulic fracturing process to improve the stimulation effect.
Nuclear magnetic resonance (NMR) is widely used to characterize the pore structure of rock. The nanoscale pores and fractures are well developed in a shale gas reservoir. The closure of nanopores caused by the increase in effective stress during the gas production process could induce stress sensitivity in shale nanopores, which has a great impact on the single-well productivity in the middle–late development stage. In this paper, shale samples from the Longmaxi Formation were taken to investigate the nanopore stress sensitivity via an NMR method. Samples with different degrees of pore and fracture development were selected and NMR experiments under different effective stress conditions were carried out. The results show that: (1) As the effective stress increases, the pore space in shale is continuously compressed, and the cumulative pore volume of shale decreases; (2) There is a more pronounced decrease in the cumulative pore volume of samples containing larger pores with the increase in effective stress. However, there are obvious differences in the pore volume changes in different pore sizes; (3) The transformation of nanopores of different sizes occurs in the process of effective stress loading. When the effective stress is small, the pores with diameters larger than 50 nm are mainly transformed to those with diameters of 10–50 nm. When the effective stress increases to a certain extent, the pores with diameters of 10–50 nm are mainly transformed to those with diameters of 0–10 nm; (4) There are significant differences in the compressibility of nanopores of different sizes. Larger nanopores generally have a higher compression coefficient and a stronger stress sensitivity. In the process of effective stress loading, the compression coefficient of pores with diameters between 10 and 50 nm changes relatively slowly, which can well-maintain the pore shape and quantity. Based on the variation in porosity ratio with effective stress, a new method of dividing shale nanopores is proposed; those with diameters smaller than 10 nm, those with diameters of 10–50 nm, and those with diameters larger than 50 nm.
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