scholarly journals Sequence Stratigraphy and Geochemistry of Oil Shale Deposits in the Upper Cretaceous Qingshankou Formation of the Songliao Basin, NE China: Implications for the Geological Optimization of In Situ Oil Shale Conversion Processing

Energies ◽  
2020 ◽  
Vol 13 (11) ◽  
pp. 2964 ◽  
Author(s):  
Penglin Zhang ◽  
Yinbo Xu ◽  
Qingtao Meng ◽  
Zhaojun Liu ◽  
Jiaqiang Zhang ◽  
...  
Keyword(s):  
Oil Shale ◽  
Arable Land ◽  
Songliao Basin ◽  
Hydrocarbon Generation ◽  
Sequence Stratigraphic ◽  
Potential Index ◽  
High Lake Level ◽  
Oil Shales ◽  
System Tracts

The Songliao Basin contains some of the largest volumes of oil shales in China; however, these energy sources are located in areas covered by arable land, meaning that the best way of exploiting them is likely to be environmentally friendly in situ conversion processing (ICP). Whether the oil shales of the Songliao Basin in the Qingshankou Formation are suitable for ICP remain controversial. In this paper, through sequence stratigraphic correlations, three main thick oil shale layers (N1, N2, and N3) of the Sequence1 (Sq1) unit in the first member of Qingshankou Formation (K2qn1) are confirmed as consistently present throughout the Southeastern Uplift region of the basin. The spectral trend attributes reflect that the lake reached a maximum flood surface of the K2qn1 in N2 oil shale layer, and the total organic carbon (TOC) and Fischer assay (FA) oil yield are significantly increasing. The N2 and N3 oil shale layers were deposited in a high lake level environment associated with ingressions of ocean water. The oil shale in these layers with the characteristics of high TOC (maximum of 23.9 wt %; average of 7.2 wt %), abundance of aquatic organic matter (OM) (maximum hydrogen index (HI) of 1080.2 mg/g; average of 889.9 mg/g) and carbonate contents (maximum of 29.5%; average of 15.4%). The N2 and N3 oil shale layers have higher brittleness index (BI) values (generally 40–50%), larger cumulative thicknesses (maximum of 13.3 m; average of 12.0 m), and much higher source potential index (SPI) values (0.92 and 0.88 tHC/m2, respectively) than the N1 oil shale layer within Sq1 transgressive system tracts (TST), indicating that the N2 and N3 layers are prospective targets for ICP. In addition, oil shales buried to depths of <1000 m have strong hydrocarbon generation capacities that make them suitable for ICP.

ORGANIC MATTER IN OIL SHALES

1980 ◽  
Vol 20 (1) ◽  
pp. 44 ◽  
Author(s):  
A.C. Hutton ◽  
A.J. Kantsler ◽  
A.C. Cook ◽  
D.M. McKirdy
Keyword(s):  
Organic Matter ◽  
Oil Shale ◽  
Large Scale ◽  
Mineral Matter ◽  
Green River ◽  
Fine Grained ◽  
Recovery Cost ◽  
Oil Shales

The Tertiary oil-shale deposits at Rundle in Queensland and of the Green River Formation in the western USA, together with Mesozoic deposits such as those at Julia Creek in Queensland, offer prospects of competitive recovery cost through the use of large-scale mining methods or the use of in situ processing.A framework for the classification of oil shales is proposed, based on the origin and properties of the organic matter. The organic matter in most Palaeozoic oil shales is dominantly large, discretely occurring algal bodies, referred to as alginite A. However, Tertiary oil shales of northeastern Australia are chiefly composed of numerous very thin laminae of organic matter cryptically-interbedded with mineral matter. Because the present maceral nomenclature does not adequately encompass the morphological and optical properties of most organic matter in oil shales, it is proposed to use the term alginite B for finely lamellar alginite, and the term lamosites (laminated oil shales) for oil shales which contain alginite B as their dominant organic constituent. In the Julia Creek oil shale the organic matter is very fine-grained and contains some alginite B but has a higher content of alginite A and accordingly is assigned to a suite of oil shales of mixed origin.Petrological and chemical techniques are both useful in identifying the nature and diversity of organic matter in oil shales and in assessing the environments in which they were formed. Such an understanding is necessary to develop exploration concepts for oil shales.

scholarly journals Particle-Size Fractionation and Thermal Variation of Oil Shales in the Songliao Basin, NE China: Implication for Hydrocarbon-Generated Process

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7191
Author(s):  
Jianliang Jia ◽  
Zhaojun Liu
Keyword(s):  
Particle Size ◽  
Vitrinite Reflectance ◽  
Thermal Analyses ◽  
Songliao Basin ◽  
Particle Analysis ◽  
Hydrocarbon Generation ◽  
Particle Sizes ◽  
Thermal Variation ◽  
Hydrocarbon Generation Potential ◽  
Oil Shales

The synchronous variation and association of organic matter (OM) and minerals in the hydrocarbon-generated process of oil shales are poorly understood. The goal of the paper is to investigate OM occurrence and thermal variation so as to reveal the hydrocarbon generation potential of oil shales. Based on detailed analyses of particle, organic, mineral, and thermal data from lacustrine oil shales in the Songliao Basin, we observed three layers of shale particles after settling in the water column characterized by a distinct color, degree of consolidation, and particle size. The particle sizes are divided into three ranges of fine grain (<1 μm), medium grain (1–20 μm), and coarse grain (>20 μm) via laser particle analysis. The particle-size distribution indicates the presence of OM polymerization and dominant contribution of the associated mineral surface and bioclastic OMs to the OM abundance of oil shale. Various OM occurrences are influenced by OM sources and redox conditions, whereas the degree of biodecomposition and particle sizes affect the placement of OM occurrences. Based on multiple thermal analyses, a synchronous response of OM and minerals to thermal variation dominates at 300–550 °C. The I/S and chlorite minerals are characterized by an entire illitization, while solid/absorbed OMs and hydrocarbon-generated water were expelled in large quantities. This contributes to major loss weights of oil shales during heating. The peak hydrocarbon-generated rate occurred at 457 °C for oil shales, corresponding to around 1.3% vitrinite reflectance value. These results are suggested to improve the understanding of OM occurrences and the thermal degradation constraint on the hydrocarbon-generated process, and contribute to the interpretation of the hydrocarbon generation potential and in-situ exploitation of oil shales.

scholarly journals A Comprehensive Simulation Model of Kerogen Pyrolysis for the In-situ Upgrading of Oil Shales

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1612-1630 ◽  
Author(s):  
K.. Lee ◽  
G. J. Moridis ◽  
C. A. Ehlig-Economides
Keyword(s):  
Oil Shale ◽  
Effective Porosity ◽  
Fractured Media ◽  
Natural Fracture ◽  
Sensitivity Analyses ◽  
Bulk Oil ◽  
System Changes ◽  
Oil Shales ◽  
Kerogen Pyrolysis

Summary Oil shale, which is composed of abundant organic matter called kerogen, is a vast energy source. Pyrolysis of kerogen in oil shales releases recoverable hydrocarbons. Here, we describe the pyrolysis of kerogen with an in-situ upgrading process, which is applicable to the majority of oil shales. The pyrolysis is represented by six kinetic reactions resulting in 10 components and four phases. Expanding the Texas A&M Flow and Transport Simulator (FTSim), which is a variant of the TOUGH + simulator (Moridis 2014), we develop a fully functional capability that describes kerogen pyrolysis and accompanying system changes. The simulator describes the coupled process of mass transport and heat flow through porous and fractured media and includes physical and chemical phenomena of reservoir systems. The simulator involves a total of 15 thermophysical states and all transitions between them and computes a simultaneous solution of 11 mass- and energy-balance equations per element. The simulator solves the equations in a fully implicit manner by solving Jacobian matrix equations with the Newton-Raphson iteration method. To conduct a realistic simulation, we account for geological structure of oil-shale reservoirs and physical properties of bulk-oil shale rocks by considering phases and components in the pores. In addition, we involve interaction between fluids and porous media, diverse equations of state (EOSs) for computation of fluid properties, and numerical modeling of fractured media. We intensively reproduce the field-production data of Shell In-situ Conversion Process (ICP) implemented in the Green River formation by conducting sensitivity analyses for the diverse reservoir parameters, such as initial effective porosity of the matrix, oil-shale grade, and the spacing of the natural-fracture network. We analyze the effect of each reservoir parameter on the hydrocarbon productivity and product selectivity. The simulator provides a powerful tool to quantitatively evaluate production behavior and dynamic-system changes during in-situ upgrading of oil shales and subsequent fluid production by thoroughly describing a reservoir model, phases and components, phase behavior, phase properties, and evolution of porosity and permeability.

In-Situ Hydrocarbon Generation Method from Oil Shale Using Hydrous Pyrolysis

2019 ◽  
Author(s):  
A. Turakhanov ◽  
A. Tsyshkova ◽  
E. Popov ◽  
A. Cheremisin
Keyword(s):  
Oil Shale ◽  
Hydrocarbon Generation ◽  
Hydrous Pyrolysis

scholarly journals Permeability evolution of pyrolytically-fractured oil shale under in situ conditions

2018 ◽  
Author(s):  
Fuke Dong ◽  
Zijun Feng ◽  
Dong Yang ◽  
Yangsheng Zhao ◽  
Dereck Elsworth
Keyword(s):  
Oil Shale ◽  
Oil And Gas ◽  
Peak Temperature ◽  
Threshold Temperature ◽  
Stress Effect ◽  
Permeability Evolution ◽  
Triaxial Stresses ◽  
In Situ Conditions ◽  
Oil Shales

In-situ injection of steam for heating of the subsurface is an efficient method for the recovery of oil and gas from oil shale where permeability typically evolves with temperature. We reported measurements on Jimusar oil shales(Xinjiang, China) at different temperatures to 600℃ and under recreated in situ triaxial stresses to obtain permeability evolution with temperature and stress. Permeability of tight oil shales evolves with temperature to a threshold temperature and peak temperature. The threshold temperature was subjected to triaxial stresses. For Jimusar oil shale, the threshold temperature ranges from 200℃ to 250℃ at ground stress of buried depth of 500m and from 350℃ to 400℃ at buried depth of 1000m. The peak temperature was almost not subjected to triaxial stress and the range is from 450℃ to 500℃ for all Jimusar samples. Pyrolysis plays an important role in permeability evolution and fundamentally changes permeability tendency and magnitude. At high temperature permeability exhibits a little reduction due to stress effect but still remains a high level due to pyrolysis. The above results show that oil shale mass can change from tight porous media into highly permeable media and oil &amp; gas can easily flow through oil shale stratum.

scholarly journals Real-time evolution of oil shale meso-structure under triaxial stress condition

2021 ◽  
Vol 248 ◽  
pp. 01049
Author(s):  
Haibo Tang ◽  
Zhiqin Kang ◽  
Kun Wang
Keyword(s):  
Oil Shale ◽  
Stress Condition ◽  
Triaxial Stress ◽  
Fracture Characteristics ◽  
Fracture Evolution ◽  
Evolution Characteristics ◽  
Triaxial Compressive Strength ◽  
Loading Tests ◽  
Oil Shales

It is significant to research the mechanical properties and micro-fracture evolution characteristics of oil shales with different bedding directions under the condition of in-situ triaxial stress loading for understanding the internal micro-characteristics of oil shales. Triaxial stress loading tests of cylindrical oil shales were carried out in two loading directions perpendicular to and parallel to the bedding, which is the S1 and S2 samples. Our results demonstrate that the oil shales are typical anisotropic and brittle fracture characteristics. The triaxial compressive strength of S1 is higher than that of S2, but the elastic modulus is almost the same. Based on the reconstructed 3D-CT image, we analyzed the dynamic evolution law of the fracture inside the sample in the horizontal and vertical directions, and obtained the distribution of the fracture in the loading process, finally revealing the internal micro-characteristics of oil shales under the different loading conditions.

Spectro-mechanical Characterization of Aromaticity and Maturity of Kerogens in Oil Shale at 6 nm Spatial Resolution

2018 ◽  
Author(s):  
Devon Jakob ◽  
Le Wang ◽  
Haomin Wang ◽  
Xiaoji Xu
Keyword(s):  
Spatial Resolution ◽  
Oil Shale ◽  
Infrared Imaging ◽  
Mechanical Characterization ◽  
Optical Diffraction ◽  
Chemical Compositions ◽  
Valuable Insight ◽  
Eagle Ford Shale

<p>In situ measurements of the chemical compositions and mechanical properties of kerogen help understand the formation, transformation, and utilization of organic matter in the oil shale at the nanoscale. However, the optical diffraction limit prevents attainment of nanoscale resolution using conventional spectroscopy and microscopy. Here, we utilize peak force infrared (PFIR) microscopy for multimodal characterization of kerogen in oil shale. The PFIR provides correlative infrared imaging, mechanical mapping, and broadband infrared spectroscopy capability with 6 nm spatial resolution. We observed nanoscale heterogeneity in the chemical composition, aromaticity, and maturity of the kerogens from oil shales from Eagle Ford shale play in Texas. The kerogen aromaticity positively correlates with the local mechanical moduli of the surrounding inorganic matrix, manifesting the Le Chatelier’s principle. In situ spectro-mechanical characterization of oil shale will yield valuable insight for geochemical and geomechanical modeling on the origin and transformation of kerogen in the oil shale.</p>

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