Geochemical and Preliminary Reservoir Characteristics of the Carboniferous–Permian Coal-Bearing Strata in the Junger Area, Northeastern Ordos Basin, China: Source Implications for Unconventional Gas

Abstract

Unconventional natural gas development, including coalbed methane, shale gas, and tight sand gas, has received extensive attention recently in coal-bearing basins. This study provides a case study of the hydrocarbon generation potential (coal and shale) and reservoir characterization (coal, shale, and sandstone) of samples from Carboniferous−Permian coal-bearing strata in the Junger area, northeastern Ordos Basin, China. Results show that the coal is dominated by vitrinite (9.3−84.1%) and inertinite (14.0−82.5%) with an average total vitrinite and inertinite content higher than 90% and maximum vitrinite reflectance (R o,max ) values from 0.44% to 0.81%. The shales contain mainly type II kerogen with high total organic carbon content (0.36−31.58%) and relatively low R o,max (0.45−0.72%). The hydrocarbon generation potential of all the shale samples ranges from 3.25 to 82.82 mg/g rock, and the hydrogen index values range from 100.31 to 768.06 mg HC/g. Three types of fluid inclusions were detected in the microfractures in/through quartz grains, particle pores, dissolution holes of calcite cement, and microfractures in calcite veins, including liquid, gas−liquid, and gas hydrocarbon inclusions, with yellow-green and blue fluorescence. The homogenization temperatures range from 60 to 140 °C, and combined with the geothermal evolution of the research area and the salinity of the fluid inclusions, the continuous charging history of unconventional gas can be divided into three stages, two hydrocarbon charging stages (80−110 °C, corresponding to Late Triassic−Middle Jurassic, and 110−140 °C, corresponding to Middle Jurassic−Middle Cretaceous) and one adjustment stage (60−80 °C, Late Cretaceous). The coal samples show the highest porosity (10.4−18.0%, avg. 14.3%) and permeability (2.17−2.93 mD, avg. 2.6 mD), followed by sandstones with porosities ranging from 10.1−13.0% (avg. 11.6%) and permeability varying between 0.51 and 1.16 mD (avg. 0.84 mD). Shale samples have the lowest porosity (1.1−4.7%, avg. 2.48%) and permeability values (0.003−0.37 mD, avg. 0.1 mD). The extensively developed and thickly deposited source rocks and multiple lithological cycles of coal-bearing strata set a good foundation for the development of unconventional gases, and the western Junger area should be newly considered as a target area for its appropriate burial depth, great hydrocarbon potential, and favorable preservation conditions.

Gas migration for terrestrial gas hydrates in the Juhugeng mining area of Muli basin, Qilian Mountains, Northwest China

“…FIs are generally trapped and preserved in crystal lattice defect and healed cracks of minerals (O’Hara and Becker, 2004; Pan et al., 2006). The generation relationship of FIs can be determined by FI position and morphology observed by an optical microscope, and the gas migration periods and paleo-temperature history can be derived from the homogenization temperature and micro-Raman spectroscopy of FIs (Tilley et al., 1989; Xu et al., 2016).…”

“…FIs in the hanging wall and footwall are characterized by the homogenization temperature of 83-115 C and 115-149 C, respectively, which means the gas had migrated into the hanging wall and footwall twice. In addition, the salinity of saline water inclusions is also an aiding indicator to determine the generations of FIs (Xu, et al, 2016). Figure 4 shows the scatter diagram between the salinity and homogenization temperature of saline water FIs, and two styles can be divided: one is low-temperature (83-115 C) and high-salinity (>6%) style, and the other one is hightemperature (115-149 C) and composite-salinity style, also indicating two generations of FIs.…”

Investigation of the controlling rock petrophysical factors on water phase trapping damage in tight gas reservoirs

“…In order to further quantify the relationship between water film and reduced gas flow in rock channels, the average thickness of the water film covering pore walls in the core samples following WPT damage was determined by using an empirical formula below 38 : where h (nm) is the thickness of water film, φ (%) is the rock porosity, S wirr (%) is the core irreducible water saturation after drainage, A (m 2 /g) is the rock-specific surface area, and ρ (g/ cm 3 ) is the rock density. Based on the experimental data obtained in this study, the thickness of the water film and the reduced pore size can be calculated using formulas (2) and (3). Calculation results are listed in Table 4 and show that the calculated thickness of water film was 21.22-38.18 nm, with an average of 27.37 nm.…”

“…Preliminary development of unconventional gas resources in the United States can be traced back to the 1970s, and development of unconventional gas resources is expected to continue long into the future as industry strives to optimize recovery of worldwide energy resources. The total volume of global unconventional gas resources, which includes tight gas, shale gas, and coalbed methane (CBM), is over 8 times the volume of conventional gas resources, and the recoverable volume of these resources is estimated to be 920 × 10 12 m 3 . The economic potential of efficiently developing these unconventional gas resources is clearly very significant.…”

The effects of solvent extraction on nanoporosity of marine-continental coal and mudstone

“…The Taiyuan and Shanxi Formations, a sequence of interbedded coal, mudstone and sandstone, deposited in a transitional environment, with alternating regression and transgression [39,59].…”