Search

• CH 4 and (sub and supercritical) CO 2 adsorption experiments on shales were performed. • The adsorption ratio of CO 2 over CH 4 for tested shale samples ranges from 1.66–8.32. • Langmuir, D-A, D-R and Ono-Kondo models were fitted to the adsorption data. • The favorable models used to fit CH 4 and CO 2 adsorption on shales are recommended. A thorough study of the adsorption behavior of shales to methane (CH 4) and carbon dioxide (CO 2) is critical for carbon dioxide sequestration in shale gas reservoirs and enhanced shale gas recovery. This paper discusses the results of an adsorption study of CH 4 and CO 2 , in single gas environment, on a set of shale samples taken from the Sichuan and Ordos Basins. The results indicated that shale exhibit higher affinity to CO 2 as compared to CH 4 under similar pressure and temperature conditions, and the preferential adsorption ratio of CO 2 over CH 4 varies between 1.66 and 8.32. Furthermore, the experimental data were modeled using Langmuir, Dubibin-Astakhov (D-A), Dubinin-Redushckevich (D-R) and Ono-Kondo models. The accuracy of the models in quantifying CH 4 and CO 2 adsorption on shale was compared using an error analysis technique. For CH 4 , both of Langmuir and D-A models performed satisfactorily with comparable accuracy. For subcritical CO 2 , the performance of the D-A model is the best. However, for supercritical CO 2 , Ono-Kondo model fitted the experimental data the best, which is the proposed model to use. The results of this study can provide the basis for the estimation of the CO 2 sequestration capacity in shale formations. [ABSTRACT FROM AUTHOR]

• Trace elements are innovatively used in the study of hydrothermally altered pyrobitumen. • Hydrothermal minerals cause enrichment of some trace elements in altered pyrobitumen. • The enrichment of trace elements varies with the optical texture change of pyrobitumen. • The hydrothermal activity is not limited to the vicinity of deep faults. The hydrothermal activity in the Ediacaran Dengying (DY) Formation in central Sichuan has modified the reservoirs and paleo-oil reservoirs; however, these modifications are not specific due to the challenges in recovering the hydrothermal scale. This paper classified pyrobitumen in the DY Formation into five categories by optical textures and analyzed the physical structure and trace element composition of the different pyrobitumen using scanning electron microscope, reflectance, and trace elements. Finally, the responses of the trace element concentrations and optical textures of the pyrobitumen to hydrothermal alteration were discussed and used to restore the hydrothermal scale in the central Sichuan Basin. The results show that isotropic, fine-grained, medium-grained, coarse-grained mosaic, and fibrous pyrobitumen develop in the DY Formation. As the optical texture of the pyrobitumen changes from isotropic to mosaic to fibrous, the order degree of aromatic lamella in pyrobitumen gradually increases, the maturity, the maximum reflectance, and the bireflectance of pyrobitumen gradually increase. Except for isotropic pyrobitumen, anisotropic pyrobitumen is subject to varying degrees of hydrothermal alteration. The hydrothermal alteration on pyrobitumen is primarily in the form of material exchange, precipitating illite, salt, and barium-enriched minerals in pyrobitumen pores and enriching some elements (Ba, Cr, Nb, and Sr) in the pyrobitumen. As the optical texture changes from isotropic to mosaic to fibrous, the element enrichment degree gradually increases. Medium-grained mosaic, coarse-grained mosaic, and fibrous pyrobitumen are widely observed in central Sichuan. Therefore, hydrothermal modification on the DY reservoirs and paleo-oil reservoirs is not limited to the deep faults but widely develop in central Sichuan, and should be an essential part of the further study of hydrocarbon accumulation. [ABSTRACT FROM AUTHOR]

The casing deformation problems during hydraulic fracturing process in shale gas wells seriously affect multi-stage hydraulic fracturing treatment and cause significant impact on efficient exploitation of shale gas in Sichuan, China. But by now, the mechanism of these casing deformation problems has not been completely understood. The tests of the casing deformation show that the shear failure is the main type of casing deformation. Combined with the detected seismic data, the fault slip caused by hydraulic fracturing is identified as the main reason for casing deformation in shale gas wells. A deep understanding of fault reactivation and slip is significant important. Hence, a semi-analytical model for calculating induced stress along the fault caused by hydraulic fracture is established in this paper. Based on the induced stress along the fault, semi-analytical models for calculating two types of fault slip are established, including the reactivated zone located at one fault tip and the reactivated zone located away from fault tips. Additionally, the effects of fluid pressure, dip angle of fault, scale of fluid stimulated area and the friction coefficient on fault slippage are discussed. At last, the method for calculating fault slippage proposed in this paper is applied in field and the calculated result is consistent with the field data. The semi-analytical model proposed in this paper provides a reasonable way for identifying casing deformation in shale gas wells or other wells which need hydraulic fracturing treatments. [ABSTRACT FROM AUTHOR]

• Shale permeability upscaling is proposed considering multiple transport mechanisms. • A REV size is determined as 420 μm with experimental data of Sichuan basin. • Bulk gas in inorganic matter contributes roughly 70% to core-scale permeability. • Water film effect can be neglected at mean pore size larger than 40 nm. This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources. [ABSTRACT FROM AUTHOR]