• Energy Research

Methane adsorption experiments over wide ranges of pressure (up to 30 MPa) and temperature (30-120 °C) were performed using a gravimetric method on the Longmaxi shale collected from the northeast boundary of Sichuan Basin, China. Organic geochemical analyses, shale composition determination, and porosity tests were also conducted. The experimental supercritical methane excess adsorption isotherms at different temperatures initially increase and then decrease with increasing pressure, giving a maximum excess adsorption capacity (Gexm = 1.86-2.87 cm/g) at a certain pressure P (6.71-12.90 MPa). The excess adsorption capacity decreases with increasing temperature below 28 MPa, while this effect reversed above 28 MPa. However, the absolute adsorption capacity decreases as the temperature increases over the full pressure range. Supercritical methane adsorption on shale is of temperature dependence because it is a physical exothermic process supported by calculated thermodynamic parameters. P is positively correlated with the temperature, while the decline rates (0.021-0.058 cm g MPa) in excess adsorption negatively correlate with the temperature. Meanwhile, Langmuir volume G (3.07-4.04 cm/g) decreases while Langmuir pressure P (1.44-4.31 MPa) increases with temperature elevation. In comparison to the actual adsorbed gas (absolute adsorption), an underestimation exists in the excess adsorption calculation, which increases with increasing depth. The conventional method, without subtracting the volume occupied by adsorbed gas, overestimates the actual free gas content, especially for the deep shale reservoirs. In situ adsorbed gas is simultaneously controlled by the positive effect of the reservoir pressure and the adverse effect of the reservoir temperature. Nevertheless, in situ free gas is dominated by the positive effect of the reservoir pressure. Lowerature overpressure reservoirs are favorable for shale gas enrichment. Geological application of gas-in-place estimation shows that, with increasing depth, the adsorbed gas content increases rapidly and then declines slowly, whereas the free gas content increases continuously. There was an equivalence point at which the contents of adsorbed and free gas are equal, and the equivalence point moved to the deep areas with increasing water saturation. Moreover, the adsorbed gas and free gas distribution are characterized by the dominant depth zones, providing the reference for shale gas exploration and development.

Methane adsorption experiments over wide ranges of pressure (up to 30 MPa) and temperature (30-120 °C) were performed using a gravimetric method on the Longmaxi shale collected from the northeast boundary of Sichuan Basin, China. Organic geochemical analyses, shale composition determination, and porosity tests were also conducted. The experimental supercritical methane excess adsorption isotherms at different temperatures initially increase and then decrease with increasing pressure, giving a maximum excess adsorption capacity (Gexm = 1.86-2.87 cm/g) at a certain pressure P (6.71-12.90 MPa). The excess adsorption capacity decreases with increasing temperature below 28 MPa, while this effect reversed above 28 MPa. However, the absolute adsorption capacity decreases as the temperature increases over the full pressure range. Supercritical methane adsorption on shale is of temperature dependence because it is a physical exothermic process supported by calculated thermodynamic parameters. P is positively correlated with the temperature, while the decline rates (0.021-0.058 cm g MPa) in excess adsorption negatively correlate with the temperature. Meanwhile, Langmuir volume G (3.07-4.04 cm/g) decreases while Langmuir pressure P (1.44-4.31 MPa) increases with temperature elevation. In comparison to the actual adsorbed gas (absolute adsorption), an underestimation exists in the excess adsorption calculation, which increases with increasing depth. The conventional method, without subtracting the volume occupied by adsorbed gas, overestimates the actual free gas content, especially for the deep shale reservoirs. In situ adsorbed gas is simultaneously controlled by the positive effect of the reservoir pressure and the adverse effect of the reservoir temperature. Nevertheless, in situ free gas is dominated by the positive effect of the reservoir pressure. Lowerature overpressure reservoirs are favorable for shale gas enrichment. Geological application of gas-in-place estimation shows that, with increasing depth, the adsorbed gas content increases rapidly and then declines slowly, whereas the free gas content increases continuously. There was an equivalence point at which the contents of adsorbed and free gas are equal, and the equivalence point moved to the deep areas with increasing water saturation. Moreover, the adsorbed gas and free gas distribution are characterized by the dominant depth zones, providing the reference for shale gas exploration and development.

Diffusion ability is an important indicator of shale gas reservoir quality. In this paper, the diffusion coefficient of the Longmaxi Formation is measured via the free hydrocarbon concentration method, and the diffusion ability, influencing factors, and seepage flow are discussed. Results show that the diffusion coefficient of the Longmaxi Formation is between 1.23 × 10−5 and 2.98 × 10−5 cm2 s−1 with an average value of 2.19 × 10−5 cm2 s−1 (confining pressure 3.0 MPa). The diffusion coefficient is calculated for various pressures using an empirical formula ( D = 0.339 K0.67/ M0.5) and experimentally measured data. The estimated, temperature-corrected diffusion coefficient of the Longmaxi Formation is 3.94 × 10−6–7.24 × 10−6 cm2 s−1 with an average value of 5.28 × 10−6 cm2 s−1 for depths from 1000 to 3000 m (confining pressure 16.7–39.7 MPa). The diffusion coefficient increases with increasing depth of the reservoir due to the changes in pressure and temperature. Fitting parameters show that the porosity of the reservoir and clay minerals is positively correlated with the diffusion coefficient, and the diffusion coefficient is also related to factors such as total organic carbon and the maximum reflectance of vitrinite ( Ro). The diffusion flow rate is 0.177–0.204 m3 d−1 with an average of 0.182 m3 d−1. Linear seepage flow is 4.95 × 10−4–14.29 × 10−4 m3 d−1 with an average of 8.87 × 10−4 m3 d−1, calculated from the diffusion coefficient and permeability per unit flow. These results indicate that the migration of shale gas in the deep region of the reservoir is mainly by diffusion. Therefore, diffusion is an important shale gas flow mechanism.

Diffusion ability is an important indicator of shale gas reservoir quality. In this paper, the diffusion coefficient of the Longmaxi Formation is measured via the free hydrocarbon concentration method, and the diffusion ability, influencing factors, and seepage flow are discussed. Results show that the diffusion coefficient of the Longmaxi Formation is between 1.23 × 10−5 and 2.98 × 10−5 cm2 s−1 with an average value of 2.19 × 10−5 cm2 s−1 (confining pressure 3.0 MPa). The diffusion coefficient is calculated for various pressures using an empirical formula ( D = 0.339 K0.67/ M0.5) and experimentally measured data. The estimated, temperature-corrected diffusion coefficient of the Longmaxi Formation is 3.94 × 10−6–7.24 × 10−6 cm2 s−1 with an average value of 5.28 × 10−6 cm2 s−1 for depths from 1000 to 3000 m (confining pressure 16.7–39.7 MPa). The diffusion coefficient increases with increasing depth of the reservoir due to the changes in pressure and temperature. Fitting parameters show that the porosity of the reservoir and clay minerals is positively correlated with the diffusion coefficient, and the diffusion coefficient is also related to factors such as total organic carbon and the maximum reflectance of vitrinite ( Ro). The diffusion flow rate is 0.177–0.204 m3 d−1 with an average of 0.182 m3 d−1. Linear seepage flow is 4.95 × 10−4–14.29 × 10−4 m3 d−1 with an average of 8.87 × 10−4 m3 d−1, calculated from the diffusion coefficient and permeability per unit flow. These results indicate that the migration of shale gas in the deep region of the reservoir is mainly by diffusion. Therefore, diffusion is an important shale gas flow mechanism.

Abstract The gas-bearing Longmaxi Formation (Fm.) records a complex tectonic history in which variations in structural and burial history directly effect the hydrocarbon maturation process. Through analysis of the tectonic-burial history, hydrocarbon maturity, and EASY% R o numerical simulations we examine three areas representing the full spectrum of geological variability in the southern Sichuan Basin, the Changning area, the Luzhou area and the Zigong area (Zishen well-1). Following deposition of the Longmaxi Fm., all three areas underwent five major tectonic events of subsidence and uplift, showing an overall long-term oscillation of the basin. The Longmaxi Fm. has undergone three major heating stages, Caledonian- Hercynian orogenesis time, the high geothermal gradient field of Hercynian and Indosinian time (approximately 200–300 Ma), and the Yanshanian-Himalayan stage. The high geothermal gradient stage is associated with extensive Emeishan flood basalts or concealed basalts, which could have played an important role in hydrocarbon maturation. The maturation process can be divided into five stages: Caledonian, Hercyninan, Indosinian, Yanshanian, and Himalayan. In the Yanshan period, the highest heating temperature of organic matter exceeded 200 °C and the maturation level was more than 2.4%, producing large amounts of natural gas, which is the main accumulation period of shale gas in the Longmaxi Fm. Due to the large amount of hydrocarbon generated, a large number of micropores were formed from organic matter evolution, especially nanoscale pores, during the middle diagenesis stage. The Longmaxi Fm. shale gas accumulation process is divided into four periods: the source-reservoir-cap deposition period, the initial accumulation period, the main accumulation period, and the adjustment period. In the main accumulation period, pyrolysis gas was dominant, which was stored within the pores, diagenetic fractures, and structural fractures in adsorbed and free state ways, forming the basic pattern of the Longmaxi Fm. shale gas. The current burial depth and structural stability of the Longmaxi Fm. are critical to gas reservoir protection.

Abstract The gas-bearing Longmaxi Formation (Fm.) records a complex tectonic history in which variations in structural and burial history directly effect the hydrocarbon maturation process. Through analysis of the tectonic-burial history, hydrocarbon maturity, and EASY% R o numerical simulations we examine three areas representing the full spectrum of geological variability in the southern Sichuan Basin, the Changning area, the Luzhou area and the Zigong area (Zishen well-1). Following deposition of the Longmaxi Fm., all three areas underwent five major tectonic events of subsidence and uplift, showing an overall long-term oscillation of the basin. The Longmaxi Fm. has undergone three major heating stages, Caledonian- Hercynian orogenesis time, the high geothermal gradient field of Hercynian and Indosinian time (approximately 200–300 Ma), and the Yanshanian-Himalayan stage. The high geothermal gradient stage is associated with extensive Emeishan flood basalts or concealed basalts, which could have played an important role in hydrocarbon maturation. The maturation process can be divided into five stages: Caledonian, Hercyninan, Indosinian, Yanshanian, and Himalayan. In the Yanshan period, the highest heating temperature of organic matter exceeded 200 °C and the maturation level was more than 2.4%, producing large amounts of natural gas, which is the main accumulation period of shale gas in the Longmaxi Fm. Due to the large amount of hydrocarbon generated, a large number of micropores were formed from organic matter evolution, especially nanoscale pores, during the middle diagenesis stage. The Longmaxi Fm. shale gas accumulation process is divided into four periods: the source-reservoir-cap deposition period, the initial accumulation period, the main accumulation period, and the adjustment period. In the main accumulation period, pyrolysis gas was dominant, which was stored within the pores, diagenetic fractures, and structural fractures in adsorbed and free state ways, forming the basic pattern of the Longmaxi Fm. shale gas. The current burial depth and structural stability of the Longmaxi Fm. are critical to gas reservoir protection.

Estimating the effectiveness of hydraulic fracturing in the context of the incrfease in the shale gas demand is of great significance for enhancing shale gas production, which aims to substantially reduce fossil energy consumption and CO2 emissions. The Zhaotong national shale gas demonstration zone has complex stress structures and well-developed fracture zones, and thus it is challenging to achieve targeted reservoir segment transformation. In this paper, we construct and optimize the geometry of hydraulic fractures at different pressures considering the upper and lower barriers in hydraulic fracturing simulation experiments and numerical modeling. The numerical simulation results show that the pore pressure exhibits a stepped pattern around the fracture and an elliptical pattern near the fracture tip. During the first time of injection, the pore pressure rapidly increases to 76 MPa, dropping sharply afterward, indicating that the fracture initiation pressure is 76 MPa. During the fracture propagation, the fracture length is much greater than the fracture height and width. The fracture width is larger in the middle than on the two sides, whereas the fracture height gradually decreases at the fracture tip in the longitudinal direction until it closes and is smaller near the wellbore than at the far end. The results revealed that the fracture width at the injection point reached the maximum value of 9.05 mm, and then it gradually decreased until the fracture width at the injection point dropped to 6.33 mm at the final simulation time. The fracture broke through the upper and lower barriers due to the dominance of the effect of the interlayer principal stress difference on the fracture propagation shape, causing the hydraulic fracture to break through the upper and lower barriers. The results of the physical simulation experiment revealed that after hydraulic fracturing, multiple primary fractures were generated on the side surface of the specimen. The primary fractures extended, inducing the generation of secondary fractures. After hydraulic fracturing, the width of the primary fractures on the surface of the specimen was 0.382–0.802 mm, with maximum fracture widths of 0.802 mm and 0.239 mm, representing a decrease of 70.19% in the maximum fracture width. This work yielded an important finding, i.e., the urgent need for hydraulic fracturing adaptation promotes the three-dimensional development of a gas shale play.

Estimating the effectiveness of hydraulic fracturing in the context of the incrfease in the shale gas demand is of great significance for enhancing shale gas production, which aims to substantially reduce fossil energy consumption and CO2 emissions. The Zhaotong national shale gas demonstration zone has complex stress structures and well-developed fracture zones, and thus it is challenging to achieve targeted reservoir segment transformation. In this paper, we construct and optimize the geometry of hydraulic fractures at different pressures considering the upper and lower barriers in hydraulic fracturing simulation experiments and numerical modeling. The numerical simulation results show that the pore pressure exhibits a stepped pattern around the fracture and an elliptical pattern near the fracture tip. During the first time of injection, the pore pressure rapidly increases to 76 MPa, dropping sharply afterward, indicating that the fracture initiation pressure is 76 MPa. During the fracture propagation, the fracture length is much greater than the fracture height and width. The fracture width is larger in the middle than on the two sides, whereas the fracture height gradually decreases at the fracture tip in the longitudinal direction until it closes and is smaller near the wellbore than at the far end. The results revealed that the fracture width at the injection point reached the maximum value of 9.05 mm, and then it gradually decreased until the fracture width at the injection point dropped to 6.33 mm at the final simulation time. The fracture broke through the upper and lower barriers due to the dominance of the effect of the interlayer principal stress difference on the fracture propagation shape, causing the hydraulic fracture to break through the upper and lower barriers. The results of the physical simulation experiment revealed that after hydraulic fracturing, multiple primary fractures were generated on the side surface of the specimen. The primary fractures extended, inducing the generation of secondary fractures. After hydraulic fracturing, the width of the primary fractures on the surface of the specimen was 0.382–0.802 mm, with maximum fracture widths of 0.802 mm and 0.239 mm, representing a decrease of 70.19% in the maximum fracture width. This work yielded an important finding, i.e., the urgent need for hydraulic fracturing adaptation promotes the three-dimensional development of a gas shale play.

Abstract A pore is an essential component of shale gas reservoirs. Clay minerals are the adsorption carrier second only to organic matter. This paper uses the organic maturity test, Field-Emission Scanning Electron Microscopy (FE-SEM), and X-ray Diffraction (XRD) to study the structure and effect of clay minerals on storing gas in shales. Results show the depositional environment and organic maturity influence the content and types of clay minerals as well as their structure in the three types of sedimentary facies in China. Clay minerals develop multi-size pores which shrink to micro- and nano-size by close compaction during diagenesis. Micro- and nano-pores can be divided into six types: 1) interlayer, 2) intergranular, 3) pore and fracture in contact with organic matter, 4) pore and fracture in contact with other types of minerals, 5) dissolved and, 6) micro-cracks. The contribution of clay minerals to the presence of pores in shale is evident and the clay plane porosity can even reach 16%, close to the contribution of organic matter. The amount of clay minerals and pores displays a positive correlation. Clay minerals possess a strong adsorption which is affected by moisture and reservoir maturity. Different pore levels of clay minerals are mutually arranged, thus essentially producing distinct reservoir adsorption effects. Understanding the structural characteristics of micro- and nano-pores in clay minerals can provide a tool for the exploration and development of shale gas reservoirs.