Lower Cambrian Shale Research Articles

Factors Affecting Shale Gas Accumulation in Overmature Shales Case Study from Lower Cambrian Shale in Western Sichuan Basin, South China

A series of comprehensive and systematic experimental data and log data of lower Cambrian Qiongzhusi Formation, from the first successful Well Jin-1 in western Sichuan Basin, were analyzed to investigate the properties of lower Cambrian organic-rich shale and to illustrate its shale gas potential, so as to investigate the factors affecting shale gas potential in overmature and ultratight shale. Trace element ratios (V/Cr and Ni/Co) and the concentrations of Cu + Zn imply the lower Cambrian shale deposited under suboxic–anoxic bottom water with high primary productivity. The organic matter is enriched in Qiongzhusi Formation as sapropelic (type I) mainly, and Ro (2.65–2.97%) values indicate the organic matter is in the overmature stage. Pores are dominated by organic pores in lower organic-rich shale and by inorganic intragranular and intergranular pores in upper organic-rich shale. Generally, organic-rich shale was deposited in anoxic shelf (high ratios of V/Cr and Ni/Co) with high productivity (high conc...

Accumulation condition and favorable area evaluation of shale gas from the Niutitang Formation in northern Guizhou, South China

In order to investigate the potential of the Lower Cambrian shale gas in South China, a study on the accumulation condition of shale gas from the Niutitang Formation was conducted. In addition, the favorable accumulation area of shale gas in northern Guizhou was evaluated. The study and evaluation were both analyzed according to the geochemical analysis data of the core and outcrop samples in this paper. The result shows that the Niutitang Formation shale in northern Guizhou is formed in the shallow sea sedimentary environment, which features moderate buried depth (<3000 m), high organic-rich shale thickness (30–110 m), high organic abundance (average TOC>3.0%), type I kerogens, over-mature thermal evolution level (Ro>2.0%), low porosity, abundant micro- and nano-meter pores and fractures, rich brittle mineral (average content >40%), and relatively high gas content (average 1.5 m3/t). The aforementioned feature indicates that the Niutitang Formation in northern Guizhou has good accumulation condition for shale gas. Through the studies above, it is proposed that the southeastern Shiqian—Yuqing—Shibing area is the most favorable area for shale gas accumulation in northern Guizhou.

Experimental Study on the Stress Sensitivity and Influence Factors of Shale under Varying Stress

Shale reservoirs are characterized by extremely low permeability and high clay content. To further study the stress sensitivity of a shale reservoir, the Lower Cambrian shale in north Guizhou was utilized. Through laboratory testing, the relationships between the shale porosity and permeability and the effective stress were established, and the stress sensitivity of shale was analysed. The mechanical properties and mineral composition of this shale were studied by rock mechanics testing and X‐ray diffraction. The main factors affecting the stress sensitivity were analysed. The results show that the porosity and permeability of this shale decrease with increasing effective stress; the shale reservoir permeability damage rate is 61.44 ~ 73.93%, with an average of 69.92%; the permeability stress sensitivity coefficient is 0.04867 ~ 0.05485 MPa−1, with an average of 0.05312 MPa−1; and the shale reservoir stress sensitivity is strong. Shale stress sensitivity is related to the rock mineral composition and rock mechanical properties. The higher the clay content in the mineral composition, the lower the elastic modulus of shale, the higher the compressibility, and the greater the stress sensitivity coefficient.

Correlation analysis of element contents and mechanical characteristics of shale reservoirs: A case study in the Cen'gong block, South China

The mechanical parameters of shale are some of the most significant assessment indices for shale gas exploitation. The development of element logging offers an opportunity to study the correlations between the elemental concentrations and the mechanical characteristics of shale. Using the Lower Cambrian shale in the Cen'gong area, Guizhou Province, China, as an example, 490 data sets are extracted using formation element and mineralogy (FEM) and cross multipole array acoustic (XMAC) logging. Through Spearman correlation analysis, the correlations between the major elements (Si, Ca, Fe, S, Ti, Mn, Mg, Al, and K) and the mechanical parameters (Young's modulus, Poisson's ratio, shear strength, shear modulus, and brittleness index) are studied. The effects of the Si content on the mechanical parameters (positive/negative correlations, magnitude and significance of the correlations) are discussed based on X-ray diffraction analyses of the minerals in 146 samples. When 1.84% < CSi (Si content) < 28.08%, Young's modulus and the brittleness index decrease with increasing Si content, and Poisson's ratio increases. When 28.08% < CSi < 31.32%, there is no significant correlation between the Si content and the mechanical parameters. When 31.32% < CSi < 44.24%, Young's modulus and the brittleness index increase with increasing Si content, and Poisson's ratio decreases. Thus, it is not reasonable to determine the mechanical properties of shale based only on the elemental composition in different regions.

Sources of ore‐forming material for Pb‐Zn deposits in the Sichuan‐Yunnan‐Guizhou triangle area: Multiple constraints from C‐H‐O‐S‐Pb‐Sr isotopic compositions

The Sichuan‐Yunnan‐Guizhou Pb‐Zn triangle area is located in the western margin of the Yangtze Block and comprises more than 400 ore deposits or prospects. This triangular area contains 200 million tons of ores at average grades of 5 wt.% Pb and 10 wt.% Zn. The Pb‐Zn ore bodies are mainly distributed as stratoid and vein types within the Neoproterozoic to Permian carbonate rocks, which are typical epigenetic Pb‐Zn mineralizations. Previous studies have mainly focused on individual deposits. In this study, the compositions of C‐H‐O‐S‐Pb‐Sr isotopes of approximately 20 typical deposits are summarized and studied in detail to reveal the source of the ore‐forming material. δ13CPDB ‐ δ18OSMOW isotopic compositions of the hydrothermal calcite, dolomite, and fluid inclusions show that CO2 in the ore‐forming fluids could have been derived from marine carbonate with subordinate incorporation of organic matter. In addition, δDH2O ‐ δ18OH2O isotopic studies also indicate the multisource features of the ore‐forming fluids, for example, meteoric water and metamorphic water; meanwhile, some deposits are related to organic fluids. The δ34S values of most sulphide minerals range from +9.0‰ to +28.6‰, similar to late Neoproterozoic to Permian seawater sulphate (+8.0‰ to +38.7‰). This similarity suggests that the reduced sulphur in sulphides could have been mainly derived from the thermochemical sulphate reduction of the host strata seawater sulphate. In addition, thermal decomposition of sulphur‐bearing organic matter could have provided some of the reduced sulphur for mineralization in some Pb‐Zn deposits. The Pb isotopic compositions of the sulphides from most deposits are totally homogeneous and located between the crustal Pb and orogenic Pb evolution curves. Comparing these deposits with the regional basement rocks, sedimentary strata, and Permian Emeishan basalts, we propose that the metals for Pb‐Zn mineralization were mainly derived from the basement rocks and sedimentary country rocks. For some deposits (e.g., Jinshachang) with highly radiogenic Pb isotopic compositions, their Pb mainly originated from Precambrian basement carbonaceous slate and Lower Cambrian shales. The (87Sr/86Sr)t ratios of sphalerite, hydrothermal calcite, and fluorite range from 0.7099 to 0.7469, higher than those of the regional sediments and the Emeishan basalts, but lower than those of the Proterozoic basement rocks. Such features also indicate the mixing source for Sr in sulphides and ore‐forming fluids. The comprehensive study of multiple C‐H‐O‐S‐Pb‐Sr isotopes from typical deposits suggests mixed sources for the ore‐forming fluids and materials in this triangular area.

Geochemical characterization and methane adsorption capacity of overmature organic-rich Lower Cambrian shales in northeast Guizhou region, southwest China

The Niutitang Shale (Lower Cambrian) is another set of organic-rich shale in addition to the Lower Silurian Longmaxi Shale in southwest China. In this study, methane adsorption capacities of both whole rock and organic matter were investigated based on adsorption isotherms measured at various temperatures (40–120 °C) and pressures (up to 35.0 MPa) for eleven Niutitang Shale samples collected from northeast Guizhou Province. The investigated samples cover a wide range of TOC contents, varying from 1.8 to 11.3%, with an average equivalent vitrinite reflectance (EqVRo) value of approximately 4.0%; their BET specific surface areas and micropore volumes range from 11.1 to 26.2 m2/g rock and between 4.3 and 11.2 cm3/kg rock, respectively, both of which are positively correlated to TOC content. Model-fitted methane maximum absolute adsorption capacities (n∞) range from 1.80 to 5.85 cm3/g rock at 60 °C and are found to largely increase with increasing TOC; this suggests that the TOC control on methane adsorption capacity obtained by other authors for other shales with relative low thermal maturity levels may be extended to a very high thermal maturity level, e.g., EqVRo≈4.0%. The methane adsorption capacity of organic matter (OM) in our shale samples, however, is somehow reduced as compared to the Lower Silurian Longmaxi Shale and other shales that display EqVRo values smaller than 3.0%, indicating thermal maturity may adversely affect methane adsorption capacity of shales when it evolves to be EqVRo≈4.0%. Nevertheless, this reduction in adsorption capacity may be compensated by the very enrichment of OM in the Niutitang Shale. In addition, a higher thermal maturity level results in a lower Langmuir pressure value, which makes it more difficult for methane desorption at reservoirs conditions. The temperature dependency of adsorption parameters was also investigated, which could be used to predict the changes of methane adsorption with burial depth under geological conditions beyond experimental temperature and pressure ranges.

Application of low-pressure gas adsorption to nanopore structure characterisation of organic-rich lower Cambrian shale in the Upper Yangtze Platform, South China

ABSTRACTThe pores in shales are mainly on a nanometer scale, and the pore-size distribution is vital with regard to the preservation and exploitation of shale gas. This study focuses on the organic-rich lower Cambrian black shale in the Upper Yangtze Platform, South China and investigates their TOC, mineralogical composition and nanopore structure. Low-pressure N2 and CO2 adsorption experiments were conducted at 77.35 K and 273.15 K, respectively, and the nanopore structures were characterised by the modified Brunauer–Emmett–Teller, Dubinin–Radushkevich, t-plot, Barrett–Joyner–Halenda and density functional theory (DFT) methods. The results indicate the following. (1) The lower Cambrian shale has a high TOC content (1.77–7.23 wt%) and a high quartz content (27.7–51.6 vol%). The total specific surface area varies from 12.02 to 28.87 m2/g. Both the total specific surface area and quartz content are positively associated with the TOC content. (2) Shale samples with a higher TOC content have a greater number of micropores, resulting in more complicated nanopore structures. Micropore volumes/surface areas and non-micropore surface areas all increase with increasing TOC content, indicating that TOC is the key factor determining the nanopore structure of the lower Cambrian shale. (3) A combination of N2 and CO2 adsorption provides the most suitable detection range (∼0.3–60 nm) and is both highly reliable and accurate with regard to nanopore structure characterisation.

Pore characteristics differences between clay-rich and clay-poor shales of the Lower Cambrian Niutitang Formation in the Northern Guizhou area, and insights into shale gas storage mechanisms

To study organic matter and pore characteristics of the Lower Cambrian Niutitang organic-rich shales, 166 shale samples from the Niutitang Formation were collected from the studied well, drilled in Kaiyang county in the Northern Guizhou area, Upper Yangtze region. All of the 166 shale cores were analysed for total organic carbon (TOC), total sulfur (TS), and the stable carbon isotope of kerogen (δ13Corg). Shale samples with varying TOC values were chosen for mineral composition analysis, helium porosity measurement and low pressure nitrogen adsorption measurement. The Lower Cambrian Niutitang Formation features high organic matter content, type I oil-prone organic matter, ultra-thick organic-rich shales, and an abundance of brittle minerals exhibiting favourable characteristics for the Lower Cambrian shale gas exploration in the Upper Yangtze region. Helium porosity measurement and low pressure nitrogen adsorption measurements were performed on selected shale samples with varying TOC content in order to analyse and characterize pore characteristics. Significant differences in mineral composition and pore characteristics were found between clay-rich and clay-poor Niutitang shales. Quartz weakly correlated with TOC content in clay-rich shales, which contained minor biogenically contributed quartz and performed better in terms of reservoir properties than clay-poor shales, and exhibited higher porosity, maximum nitrogen quantity adsorbed, pore volume, and specific surface area. In clay-rich shales, the maximum nitrogen quantity adsorbed, total pore volume, and specific surface area positively correlated with TOC content (R2=0.77, 0.79, and 0.75, respectively). The pore volume of clay-rich shales was dominated by mesopores, and both micropore and mesopore volume of clay-rich shales correlated significantly with TOC content. In clay-poor shales, quartz positively correlated with TOC content, indicating biogenic contribution to quartz. Micropore volume and mesopore volume of clay-poor shales were weakly positively correlated with TOC content. Pore volume, especially mesopore volume, may be affected by the recrystallization of biogenic silica, exhibiting identical micropore volume with clay-rich shales but lower mesopore volume.

Differential fluid migration behaviour and tectonic movement in Lower Silurian and Lower Cambrian shale gas systems in China using isotope geochemistry

Isotope geochemistry has been introduced as a means to trace origin of the hydrocarbon and characterize highly productive shale gas systems recently. To assess the impact of tectonic movement and the sealing of shale gas systems, isotope geochemistry, pressure coefficients and the distribution of bitumens are analysed. Many samples yield isotope geochemical data with typical carbon isotopic reversals (δ13C1 > δ13C2) and hydrogen isotopic reversals (δ13DC2H6 > δ13DCH4) in the Lower Silurian shale gas. Isotopically reversed gases are considered to originate in sealed, self-contained petroleum systems. Besides, isotope “reversals order” degree of shale gas has positive correlation with gas production. Isotopically normal gases from the Lower Cambrian indicate that this formation was a continued relatively open petroleum system when oil and gas generated. The pressure coefficients of the Lower Silurian shale gas reservoir range from 1.45 to 2.03, indicating that the reservoir is overpressurized, whereas the Lower Cambrian shale gas reservoir possesses a normal pressure system. Overpressurization of the Lower Silurian shale gas reservoir also indicates that it is a well-sealed system. The distribution and isotope geochemistry of bitumens in the Sinian dolomite and Cambrian shale suggests that the source rock of the Sinian hydrocarbon is the Cambrian shale. An unconformity induced from tectonic movement during the Tongwan period is interpreted to be the fluid migration tunnel and the cause of the differential shale gas content and production. Finally, the isotopic reversals associated with maturity, pressure coefficients and tectonic evolution can both assess the preservation conditions of the reservoir and explain the differential fluid migration behaviour.

Preliminary study of pore structure and methane sorption capacity of the Lower Cambrian shales from the north Gui-zhou Province

The organic carbon content (TOC), mineral composition, specific surface area, porosity, pore volume and methane sorption capacity (MSC) of the Lower Cambrian Niu-ti-tang and Pa-lang shales from north Gui-zhou Province were investigated, aiming to characterize the pore structure and its controlling factors and the sorption capacity of these shales. The results indicate that these shales are characterized by low porosity and permeability, with a BET specific surface area ranging from 5.64 to 28.29 m2/g and micropore and mesopore volumes ranging from 0.02 to 0.54 cm3/100 g and 0.53–3.38 cm3/100 g, respectively. The positive correlations between porosity, specific surface area, micropore volume and TOC content suggest that organic matter is a primary factor in the pore structure development. However, the shales with TOC content of above 5% display a much low micropore volume and specific surface area. The Lower Cambrian shales display an excess MSC at 12 MPa (nex12MPa) and Langmuir MSC (nL) ranging from 0.30 cm3/g to 3.71 cm3/g and 0.41 cm3/g to 4.22 cm3/g, respectively. Both of the MSCs exhibit a positive correlation with TOC but no correlation among these shales with TOC content above 5% due to the lesser degree of organic pore development. In addition, the sorption capacity of these shales displays a fan-shaped positive correlation with the BET specific surface area and suggests that the higher BET specific surface area does not always result in high MSC in shales. Finally, the Pa-lang shales display a better pore property and higher MSC than that of the Niu-ti-tang shales and appear to be superior prospective shale gas reservoirs.

Numerical study of multi-period palaeotectonic stress fields in Lower Cambrian shale reservoirs and the prediction of fractures distribution: A case study of the Niutitang Formation in Feng'gang No. 3 block, South China

Fractures not only control the distribution of oil and gas reservoirs, but also are key points in the research of oil and gas reservoir development programmes. The tectonic fractures in the Lower Cambrian shale reservoirs in the Feng'gang No. 3 block are effective reservoir spaces for hydrocarbon accumulation, and these fractures are controlled by palaeotectonic stress fields. Therefore, quantitatively predicting the development and distribution of tectonic fractures in the Lower Cambrian shale reservoir is important for the exploration and exploitation of shale gas in the Feng'gang No. 3 block. In the present study, a reasonable geological, mechanical and mathematical model of the study area was established based on the faults systems interpreted from seismic data, fracture characteristics from drilling data, uniaxial and triaxial compression tests and experiments on the acoustic emissions (AE) of rocks. Then, a three-dimensional (3-D) finite element method is applied to simulate the palaeotectonic stress field with the superposition of the Yanshan and Himalayan movements and used to predict the fracture distribution. The simulation results indicate that the maximum principal stress value within the study area ranged from 269.97 MPa to 281.18 MPa, the minimum principal stress ranged from 58.29 MPa to 79.64 MPa, and the shear stress value ranged from 91.05 MPa to 106.21 MPa. The palaeotectonic stress field is controlled by the fault zone locations. The fracture development zones are mainly controlled by the tectonic stress fields and are located around the faults, at the end of the fault zones, at the inflection point and at the intersection of the fault zones.

Reservoir characteristics and well-logging evaluation of the Lower Cambrian shales in southeast Chongqing, China

AbstractTo accurately identify the reservoir characteristics and main controlling factors of the Cambrian Niutitang black shale in the southeast Chongqing, a series of systematic measurements were conducted on core samples from Well Yuke-1 and Well Youke-1. The measurements include clay mineral analysis, XRD analysis, petrophysical properties, specific surface area, pore diameter and TOC, as well as Ro and maceral compositions. The Niutitang shale reservoir contains detrital minerals and clay minerals averagely of 51.34% and 32.74%, respectively. The average effective porosity and permeability are 1.2% and 8.0×10-3mD, respectively, typically of ultra-low porosity and permeability. Mesopores are dominant, accounting for approximately 73% of the total pore volume. The average BET specific surface area is 7.75m2/g and the average pore diameter is 5.3nm. The average TOC is 2.29% and the average Ro is 3.12%, indicating that the organic matter is in over-maturity stage. Statistical analyses of the measurements show that the micropore volume is positively correlated with TOC but negatively correlated with the total content of clay minerals; the mesopore volume is positively correlated with TOC, the total content of clay minerals and the content of carbonate minerals; the macropore volume is positively correlated with TOC and the content of carbonate minerals, weakly positively correlated with the content of detrital minerals but negatively correlated with the total content of clay minerals. The porosity and TOC of the Niutitang shale are computed using the conventional well-logging method for the Yuke-1 and Youke-1 wells, and the porosities are quite consistent with the core analysis resultsr, but in the shallow reservoir that contains no oil and gas, the TOC exhibits no correlation with the core analysis results.

Stable isotope geochemistry of the nitrogen-rich gas from lower Cambrian shale in the Yangtze Gorges area, South China

The organic-rich marine shales from the lower Cambrian Niutitang formation in the Yangtze Gorges area are characterized by their high TOC values (0.54–5.13%), types I and II organic matter, and high Ro values (2.4%–2.6%). Geochemical parameters of 19 gas samples from the lower Cambrian shale formation from well ZD-1 were analyzed in this study. The gases are dominated by methane, with small amounts of ethane and no propane or butane. The δ13C(CH4) values range from −31.7‰ to −27.9‰, the δ13C(C2H6) values range from −35.2‰ to −33.4‰, and the δ2H(CH4) values range from −214‰ to −187‰. Furthermore, carbon isotopic compositions of the alkane gases from the lower Cambrian shale are characterized by δ13C1 > δ13C2; these results indicate that the gases are of thermogenic origin and are oil-derived. Moreover, methane with heavy carbon isotopic and light hydrogen isotopic values may be produced when water reacts with inorganic carbon. The isotopic reversal of alkane gases was probably due to destructive redox reactions at maximum burial resulting in Rayleigh-type fractionation and/or mixing by gases from the same source but at a different maturity. Nitrogen occurs in the analyzed gases at concentrations from 8.15 to 96.52%, and the δ15N(N2) values vary from 3.2 to 7.4‰. The δ15N(N2) values and high illite content suggest that nitrogen was mainly generated during thermal transformation of organic matter and/or from NH4-rich illites of the clayey facies of the lower Cambrian shale. Carbon dioxide concentrations vary from 1.13 to 4.96%, and the δ13C(CO2) values range from −8.9 to −13.6‰. This suggests that carbon dioxide was mainly generated during thermogenic processes of transformation of organic matter. Moreover, the major reason for the change in nitrogen and methane contents in the studied well (ZD-1) is probably due to the development of micro cracks in core samples with high contents of nitrogen. A high nitrogen content may be caused by the strong adsorption capacity of nitrogen, which leads to the retention of nitrogen and the diffusion of methane in shale.

Well log evaluation of shale gas reservoirs and preservation conditions of Lower Cambrian shale succession in Cengong Block of southeast Sichuan basin, south China

The abundant lower Cambrian marine shale gas resources discovered in south China is of great potential for exploitation. In particular, Cengong Block, which is located in a complex tectonic deformation region of southeast Sichuan basin, south China, is one of the marine shale gas exploring areas currently. In this area, folds and faults are well developed, mainly strike in NE or NNE directions. Lower Cambrian marine shale is characterized by great thickness and regional extensive distribution. Lower Cambrian strata in this region is mainly consisted of deep shelf deposits. Sandstone and limestone are determined based on GR log and neutron-density cross plot. Lower Cambrian shales in Cengong Block are associated with high GR value and TOC. Relatively low content of Thorium (Th) and Potassium (K) indicates low clay content. Neutron-density crossover is usually associated with gas-bearing shale beds. Brittle shale beds are well developed and the gas storage capacity of lower Cambrian shale reservoir has been affected by faulting and folding to some extent. Small-scale water-bearing caves are developed in the limestones and dolomites of lower Cambrian strata which usually displays low-pressure anomalies. Although the lower Cambrian shale reservoir in study area is characterized with distinct gas-bearing properties and shale gas flow has been obtained after fracturing, it is essential to recognize that the preservation conditions of shale gas accumulation are affected by tectonics, formation water and pressure coefficient.

Characterization of the reservoir in Lower Silurian and Lower Cambrian shale of south Sichuan Basin, China

Natural gas has become an important source of energy. In China, external dependency on natural gas reached 32.2%. China is rich in shale gas resources, and both government and oil companies have promoted the development of shale gas. Lower Silurian Longmaxi Formation (LSLF) shales and Lower Cambrian Qiongzhusi Formation (LCQF) shales are believed to be favorable shale gas targets in the Sichuan Basin. Oil companies have extracted gas from LSLF shale but not from LCQF shale in and around the Sichuan Basin. The total organic carbon content (TOC) increases with buried depth in LSLF shales and LCQF shales, but the organic matter (OM) in the LCQF shales is more compacted than LSLF shales. The mineral brittleness index of these shales means that they are favorable for hydraulic fracturing to generate the complex fracture geometry in both shales. The OM is rich in the pores and the surface porosity of OM is from 7.18 to 9.52% in the LSLF shale and LCQF shales with low TOC (TOC <1.0%). The LCQF shales with high TOC are poor in the OM host pores and surface porosity of OM is less than 0.1%. The gas contents of LSLF shales increase with the TOC contents, but there is a poor correlation in LCQF shales, especially in LCQF shales with TOC of greater than 3.0%. There was a linear correlation between gas content and VTOC in both shales, which was multiplied by the TOC and surface porosity. For the LCQF shales, the TOC and the surface porosity of OM are also important to the shale gas content and selection of favorable resource targets. The TOC of LCQF shales was less than 1.0% and greater than 3.0% in this paper, so the inflection point of surface porosity should be further examined in OM.

Rare earth elements (REEs) geochemistry of Sinian–Cambrian reservoir solid bitumens in Sichuan Basin, SW China: potential application to petroleum exploration

AbstractIn order to evaluate rare earth elements (REEs) as a potential proxy for solid bitumen classification, we employed traditional correlation approaches, such as carbon isotopes and V/(V + Ni) ratios, to infer the source rocks of Sinian–Cambrian reservoir solid bitumens in the Sichuan Basin and analyse solid bitumens for their REE compositions by inductively coupled plasma–mass spectrometry. Our data suggested that Sinian–Cambrian reservoir solid bitumens were primarily sourced from the lower Cambrian shales deposited under anoxic–euxinic conditions. REE and their associated parameters seemed to be more sensitive to classify solid bitumens than traditional correlation approaches. REE concentrations played a dominant role and fractionation degree between light and heavy REE and played a secondary role in solid bitumen classification. REE concentration and pattern in solid bitumens might be controlled by two processes, including inheritance from source rocks and water–rock interaction. The major factor controlling REE concentrations in solid bitumens was the type of organic matter of source rocks. Authigenic minerals in solid bitumens formed by water–rock interaction appeared to have little influence on REE compositions of solid bitumens because of their trace contents. Overall, REE could be used as a novel complementary approach to solid bitumen classification in complicated petroleum systems. Copyright © 2015 John Wiley &amp; Sons, Ltd.

Natural Fractures and Their Effects on Reservoir Reconstruction in Lower Cambrian Shale, Southeast Chongqing, China

Natural fractures in shale are important for the preservation and exploitation of shale gas. The classification of fracture types and characterization of system parameters would help to better evaluate reservoir properties. An evaluation of the relationship between natural fractures and hydraulic fractures may help to predict the effects of fracturing on reservoir properties and assist fracturing design. This study focuses on fractures in Lower Cambrian marine shale in southeast Chongqing, China. The fracture system is characterized in detail through observations and descriptions of several outcrops, cores, and thin sections. Hydraulic fracturing experiments were conducted using a large-size triaxial simulator, enabling us to discuss the effects of natural fractures on the creation of hydraulic fractures in a reservoir. The shale contains three primary fracture types: structural fractures, digenetic fractures, and abnormal pressure fractures. High-angle shear fractures (75°–90° from bedding) are the dominant type of seepage fractures observed in the study area. Three sets of tectonic fractures were formed during three tectonic movements. East–west fractures formed mainly in the Yanshanian. Hydraulic fracturing experiments indicated that the Lower Cambrian shale had a good level of reconstruction. The interference between natural fractures and hydraulic fractures has resulted in the segmentation. This study maybe have some reference for fracturing parameter design.

Features and origin of natural gas in the Sinian–Cambrian of central Sichuan paleo-uplift, Sichuan Basin, SW China

Abstract Based on the new drilling data and field outcrop data of the Gaoshiti–Moxi area, the geochemical characteristics of the Sinian-Cambrian natural gas are studied and analyzed, including gas composition, isotope, light hydrocarbon, kerogen carbon isotope and reservoir bitumen biomarkers etc. The results show that: (1) The natural gases of the Sinian Dengying Formation and Cambrian Longwangmiao Formation, mainly composed of hydrocarbon gas, are typical dry gas. However, the natural gas of the Dengying Formation is characterized by higher dry coefficient, lower content of hydrocarbon gas and higher content of non-hydrocarbon gas. The main differences in non-hydrocarbon gases are the contents of N 2 , CO 2 , H 2 S and He, the small composition differences between the natural gas of Dengying Formation and that of Longwangmiao Formation are mainly caused by maturity differences of source rocks and H 2 S generated by reaction between sulfide mineral and hydrocarbons. (2) There are obvious differences in δ 13 C 2 between the natural gases in Dengying Formation and Longwangmiao Formation, showing different parent materials of them. (3) There are large differences in δ 2 H between the natural gases of Dengying Formation and Longwangmiao Formation, showing the different water salinities of their source rock depositional environment. (4) The average kerogen carbon isotope values of the Lower Cambrian shale, Dengying Formation mudstone, Doushantuo Formation mudstone and Dengying Formation carbonates are −32.8‰, −31.9‰, −30.7‰ and −27.8‰ respectively. (5) The ratio of 4-methyl dibenzothiophene to 1-methyl dibenzothiophene of Dengying Formation bitumen is between that of Qiongzhusi Formation and Dengying Formation source rocks. It is believed that the Sinian-Cambrian natural gas in the Gaoshiti-Moxi area is mainly oil cracking gas, the Sinian natural gases come from the Sinian and Cambrian source rocks, and the Cambrian natural gases mainly come from Cambrian source rock.

Geochemical and geological characteristics of the Lower Cambrian shales in the middle–upper Yangtze area of South China and their implication for the shale gas exploration

During the Early Cambrian, the middle–upper Yangtze area of South China evolved to an open shelf with anoxic bottom waters prevailing in most places. Accumulated black shales in this area, named Niutitang Formation (Qiongzhusi Formation in some places), thus become the prospective resources for shale gas exploration and development. Based on compiled petrological and organic geochemistry data, and other information obtained by relevant laboratory tests and field investigation, we documented regional distributional patterns of Lower Cambrian organic-rich shales in the middle–upper Yangtze area according to their lateral extent, thickness, total organic carbon, thermal maturity and burial depth. This study also features the general reservoir properties of dark shales in this area. Together these results highlight several most favorable areas including Youyang-Xiushan-Huayuan, Suiyang-Daozhen-Dejiang, Shiqian-Sinan-Yinjiang, Jiangkou-Tongren-Songtao and Huangping-Shibing for shale gas exploration.

Characterization of the Lower Cambrian Shale in the Northwestern Guizhou Province, South China: Implications for Shale-Gas Potential

The Lower Cambrian shale in the Northwest part of the Guizhou Province (NWG), South China, has recently been considered as a potential shale gas reservoir because of its large distribution and high total organic carbon (TOC) content. An integrated characterization about this shale succession is provided in this study to illustrate its shale gas potential. The shale in the NWG area is characterized by high TOC content and high thermal maturity. The mineralogical composition and lithofacies assemblage of the NWG shale are compared with hot shales for analogy and found to be greatly similar to the Barnett shales. Five different genetic types of pores have been identified by scanning electron microscopy. The porosity shows no correlation with the quartz and clay ratios, but it correlates well with the TOC content, suggesting that organic matter pores have contributed a lot to the total porosity. The pore size distribution is evaluated by pore volume and surface area based on diameter, indicating that the micr...