Xiaoyue Gao

Diagenetic process and pore evolution of Jurassic continental shale in Tarim Basin, Northwest China

The Jurassic shale in the Tarim Basin, as one of the important source rocks within the basin, is identified as a set of typical continental sedimentation with big hydrocarbon-generating potential. The diagenetic process and pore evolution characteristics of the Jurassic shale were studied based on geochemical and reservoir bed properties analyses and scanning electron microscope (SEM) observation. The results show that the Jurassic shale shows low-porosity and low-permeability, the mineral composition is mainly of clay mineral and quartz; the shale underwent three diagenetic evolutionary stages, namely syngenetic to Period A of early diagenetic stage, Period B of early diagenetic stage and Period A of middle diagenetic stage; during this process, the shale underwent a series of changes such as hydrocarbon generation of organic matter, conversion from original minerals to illite, formation of authigenic minerals, recrystallization and corrosion; meanwhile, porosity and permeability also underwent the evolutionary processes including rapid reduce of primary pore and development of secondary pore. The pore development within shale is mainly controlled from three aspects, namely material composition of rock, diagenesis and later tectonic reworking.

The characteristics of unconformity surface at the bottom of the Paleogene and its significance in hydrocarbon migration in the Sikeshu Sag of the Junggar Basin, Northwest China

The unconformity surface at the bottom of the Paleogene, located in the Sikeshu Sag of the Junggar Basin, Northwest China, is one of the most important hydrocarbon migration pathways and characterized by 3 layers of upper coarse clastic rock, lower weathering crust and leached zone. The upper coarse clastic rock displays features of higher density, lower SDT and gamma-ray logging while the weathering crust in the lower part displays opposite features. The formation water is of NaHCO3 type but at lower mineralization degree. The QGF indices are generally between 2.19 and 3.77 and the GOI parameters vary from 1% to 5%. From the southeast to the northwest of the sag, the content of saturated hydrocarbon increases from 30.81% to 53.74% while that of non-hydrocarbon and asphaltene decreases. The Pr/nC17 decreases from 0.65 to 0.47 while the Ph/nC18 decreases from 0.66 to 0.27, and the content of benzo[c] carbazole declines while the benzo[a] carbazole amount and (alkyl carbazole)/(alkyl+benzo carbazole) ratio both increase. These revealed that the hydrocarbons migrated from the sag to the ramp region along the unconformity surface.

The Main Control Factors for Shale Gas Accumulation and Exploration Problems in Shale Gas of South China

remarkable profits, and four national shale gas demonstration zones (Fuling Jiaoshiba, Changning Weiyuan, Zhaotong, and Yanchang) have been established. Recently, nearly 400 drilling wells have been accomplished, including 143 vertical wells and 130 horizontal wells. But the shale gas production varies widely, as the main control factors of enrichment conditions and accumulation mechanism of shale gas is still not enough studied, which fundamentally restricts the shale gas exploration and development process. In this paper, samples from the lower Silurian Longmaxi marine shale in South China were taken to investigate the main factors of shale gas accumulation. Shale pore structure characteristics, lithofacies, gas occurrence, and preservation condition were studied by using geochemical analysis, microscope image analysis, X -ray diffraction, low pressure N2 isotherm analysis, and field emission scanning electron microscope (FE-SEM). The results show that shale lithofacies controls the organic matter richness and brittle mineral content. Organic-rich siliceous shale, which occurred in deep shelf at the bottom of the Longmaxi formation in the study area, has a high organic carbon content, high brittleness index, high effective porosity, and high gas content. Moreover, the high organic carbon content means the high hydrocarbon potential, and the high brittleness index represents a favorable fracturing. Multi-scale pore structure controls the shale gas occurrence and content. Mesopores (2~50nm) are well developed in organic matter, which impact the sorption and diffusion of shale gas. Macropores (>50nm) are well developed along with brittle minerals, which impact the storage and transfusion of shale gas. Shale gas occurrence varies as geological conditions changes at the different evolution stages. Combined with burial history and hydrocarbon generation of organic matter, shale gas occurrence evolution is divided into 4 stages: early biological free gas, pyrolysis sorption gas, pyrolysis free gas, late period free gas. Preservation condition is one of the most important control factors influencing target area optimization. Regional tectonic styles which are beneficial to shale gas accumulation are mainly wide syncline and small inclination monoclinic. The low fracture density, small erosion thickness, thick overlying strata, and low diffusion coefficient, are control the conservation of shale gas, which affect the accumulation of shale gas. Currently, the researches of shale heterogeneity, multiscale pore structure, target area prediction, and objective evaluation are still quite little. JIANG Zhenxue, TANG Xianglu, LI Zhuo, JI Wenming, GAO Xiaoyue, YUAN Yuan and WANG Pengfei, 2015. The Main Control Factors for Shale Gas Accumulation and Exploration Problems in Shale Gas of South China. Acta Geologica Sinica (English Edition), 89 (supp.): 250.

The origin and alteration of calcite cement in tight sandstones of the Jurassic Shishugou Group, Fukang Sag, Junggar Basin, NW China: implications for fluid–rock interactions and porosity evolution

ABSTRACT The Shishugou Group, which consists of Middle Jurassic Toutunhe Formation and Upper Jurassic Qigu Formation, is currently an important hydrocarbon exploration target in the Fukang Sag of Junggar Basin, China. The Shishugou Group sandstones experienced a complex diagenetic history with deep burial (3600–5800 m) to develop low–ultralow porosity and permeability reservoir with some high-quality reservoirs found in the tight sandstones owing to the reservoir heterogeneity. This integrated petrographic and geochemical study aims to unravel the origin and alteration of calcite cement in the Shishugou Group sandstones and predict fluid–rock interaction and porosity evolution. The Shishugou Group sandstones (Q43.8F7.4R48.8) have a dominant calcite cement with strong heterogeneity forming in two generations: poikilotopic, pore-filling masses that formed at an early diagenetic stage and isolated rhombs or partial grain replacements that formed at a late stage. The Shishugou Group, which are lacustrine sediments formed in low–medium salinity lake water in a semiarid–arid climatic environment, provided the alkaline diagenetic environment needed for precipitation of chlorite and early calcite cements in early diagenesis. The Ca2+ of the pore-filling calcite cements was sourced from weathering or dissolution of volcanic clasts in the sediment source or during transport in under oxidising conditions. The δ18OV-PDB and δ13CV-PDB values of calcite were significantly controlled by distance from the top unconformity and underlying coal-bearing stratum with carbon sourced from atmospheric CO2, and organic matter. The early carbonate cement inhibited burial compaction producing intergranular pore spaces with enhanced reservoir properties by late dissolution under acidic conditions. Anhydrite cement reflects reaction of organic acid and hydrocarbon with the sandstones and is associated with fluid migration pathways. The fluid–rock interactions and porosity evolution of the tight deep sandstones produced secondary pores that filled with hydrocarbon charge that forms this deep high-quality reservoir.

Geological and geochemical characteristics of the Middle–Lower Jurassic shales in the Kuqa Depression, Tarim Basin: an evaluation of shale gas resources

ABSTRACT Middle–Lower Jurassic terrigenous shales constitute a set of significant hydrocarbon source rocks in the Kuqa Depression of the Tarim Basin. Until recently, however, most investigations regarding this set of hydrocarbon source rocks have mainly focused on conventional oil and gas reservoirs, and little research has been conducted on the formation conditions of shale gases. This research, which is based on core samples from nine wells in the Kuqa Depression, investigated the geological, geochemical, mineralogical and porosity characteristics of the shales, analysed the geological and geochemical conditions for the formation of shale gases, and evaluated the shale gas resource potential. The results show that the distribution of the Middle–Lower Jurassic shales is broad, with thicknesses reaching up to 300–500 km. The total organic carbon (TOC) content is relatively high, ranging from 0.2 to 13.5 wt% with a mean of 2.7 wt%. The remaining hydrocarbon generative potential is between 0.1 and 22.34 mg/g, with a large range of variation and a mean value of 3.98 mg/g. It is dominated by type III kerogen with the presence of minor type II1 kerogen. The vitrinite reflectance values range from 0.517 to 1.572%, indicating the shales are in a mature or highly mature stage. The shales are mainly composed of quartz (19–76%), clay (18–68%) and plagioclase (1–10%) with mean contents of 50.36 wt%, 41.42 wt%, and 3.37 wt%, respectively. The pore spaces are completely dominated by primary porosity, secondary porosity and microfractures. The porosity is less than 10% and is mainly between 0.5 and 4%, and the permeability is generally less than 0.1 mD. These results classify the shale as a low-porosity and ultra-low-permeability reservoir. The porosity has no obvious correlation with the brittle or clay mineral contents, but it is significantly positively correlated with the TOC content. The maximum adsorbed gas content is between 0.82 and 8.52 m3/t with a mean of 3.37 m3/t. In general, the shale gas adsorption content increases with increasing the TOC content, especially when the TOC content is greater than 1.0%. The volumetric method, used to calculate the geological resources of the Middle–Lower Jurassic shales in the Kuqa Depression, shows that the geological resources of the Middle and Lower Jurassic shales reach 667.681 and 988.115 × 109 m3, respectively with good conditions for the formation of shale gas and good prospects for shale gas exploration.

Gas Occurrence and Accumulation Characteristics of Cambrian-Ordovician Shales in the Tarim Basin, Northwest China

The Tarim Basin is located in northwestern China and is the biggest basin in China with huge oil and gas resources. Especially the Lower to Middle Cambrian and Middle to Upper Ordovician possess the major marine source rocks in the Tarim Basin and have large shale gas resource potential. The Cambrian–Ordovician shales were mainly deposited in basin–slope facies with thicknesses between 30–180 m. For shales buried shallower than 4500 m, there is high organic matter abundance with TOC (total organic carbon) mainly between 1.0% and 6.0%, favorable organic matter of Type I and Type II, and high thermal maturity with Ro as 1.3%–2.75%. The mineral composition of these Cambrian– Ordovician shale samples is mainly quartz and carbonate minerals while the clay minerals content is mostly lower than 30%, because these samples include siliceous and calcareous shale and marlstone. The Cambrian and Ordovician shales are compacted with mean porosity of 4% and 3%, permeability of 0.0003×10–0.09×10 μm and 0.0002×10–0.11×10 μm, and density of 2.30 g/m and 2.55 g/m, respectively. The pores in the shale samples show good connectivity and are mainly mesopore in size. Different genetic types of pores can be observed such as intercrystal, intergranular, dissolved, organic matter and shrinkage joint. The reservoir bed properties are controlled by mineral composition and diagenesis. The maximum adsorption amount to methane of these shales is 1.15–7.36 cm/g, with main affecting factors being organic matter abundance, porosity and thermal maturity. The accumulation characteristics of natural gas within these shales are jointly controlled by sedimentation, diagenesis, hydrocarbon generation conditions , reservoir bed properties and the occurrence process of natural gas. The natural gas underwent short-distance migration and accumulation, in-place accumulation in the early stage, and adjustment and modification in the later stage. Finally, the Yulin (well Y1) and Tazhong (well T1) areas are identified as the targets for shale gas exploration in the Tarim Basin.

Main Factors Control the Shale Gas Accumulation in the Yudongnan Area, Southwest China

ancient marine shales in southern china, especially in the Jiaoshiba-Fuling area. However, rare succeed exploration and production cases outside Sichuan basin were reported. The main reason for this issue can be attributed to the misunderstandings of the mechanisms of shale gas accumulation and key controlling factors. In order to better understand the mechanisms and discuss the factors of maturity, reservoir property, fluid pressure, gas content, preservation conditions effects on shale gas accumulation, black shale core samples were collected from a well drilled in the Yudongnan area, in southwest China and geochemistry, mineralogy, lithofacies, pore structures, reservoir properties and occurrence state were investigated using shale thin section, X-ray diffraction low pressure N2 and CO2 adsorption analysis and field emission scanning electron microscopy (FE-SEM) observations. The results show that the black shales have total organic carbon (TOC) values ranging from 1.82% to 4.35% and their equivalent vitrinite reflectance values are in the range of 2.5% to 3.5%. Both mineral matrix and organic matter pores are well developed with pore sizes ranging from several to several hundred nanometers observed by FESEM. The total porosity for the samples ranges from 1.60% to 5.78% and the percentages of organic matter porosity are estimated to be in the range of 8% to 32%. The total surface area ranges from 3.1 m/g to 22.56 m/g and the micropore (< 2 nm) surface area estimated ranges from 1.18 m2/g to 12.74 m/g. The TOC values have positive relationships with the total porosity, total surface area and the micropore (< 2 nm) volume and surface area, indicating TOC may be an effective parameter for shale gas reservoir evaluation in the studied area. At a given temperature and pressure, the gas sorption capacities of shales are primarily controlled by the TOC but may be significantly affected by the type and maturity of the organic matter, mineral composition (especially clay content), moisture content, pore volume and structure, leading to different gas sorption capacity for different shales. Under geologic conditions, the gas sorption capacities increases initially with depth due to the predominating effect of pressure, passes through a maximum, and then decreases because of the influence of increasing temperature at greater depth. As temperature and pressure increase and with the presence of moisture, the gas sorption capacities of organic-rich shales are quite low. High contents of free gas in organic-rich shales (47.22%~82.78%) can be preserved in relatively closed system and low diffusion coefficient shales, which have the structure characteristics of flat syncline and low angle unicline, less fracture, low erosion thickness, and thick shale layers. Loss of free gas during post-accumulation tectonic movement and erosion may result in under saturation (the total gas contents lower than the sorption capacity). For the shale gas exploration areas with a strong structure deformation, the preserved condition of the shale system was destroyed to a certain degree with a pressure decrease and loss of large amount of free gas. LI Zhuo, JIANG Zhenxue, LIU Luofu, GAO Xiaoyue, JI Wenming, XIONG Fengyang and SONG Yan, 2015. Main Factors Control the Shale Gas Accumulation in the Yudongnan Area, Southwest China. Acta Geologica Sinica (English Edition), 89(supp.): 263.