Search

Abstract Recent significant breakthroughs have been made of the Lower Silurian shale gas in the Changning-Zhaotong blocks recently, the key exploration area of China. Through comparative research of the gas geochemistry, Longmaxi Formation shale gas is mainly composed of methane (98.8%), with extremely low wetness coefficient (0.49%), and possesses negligible quantities of ethane and propane. The Non-hydrocarbon gases are mainly composed of small-scale quantities of N 2 and CO 2 of mixed origin. Enriched δ13C 1 (from −29.4‰ to −26.7‰) and δ13C 2 (from −34.5‰ to −31.6‰) values, together with sapropelic organic matter, indicate a typical overmature oil-type gas. Abnormal geochemical characteristics of shale gas (δ13C 1 > δ13C 2 > δ13C 3) result from merged secondary impacts in the high-maturity and well-confined shale reservoirs, like the mixing of secondary cracking gases, Rayleigh fractionation of C 2 when transition metals and water undergo redox reactions. Notable geographic variation can also be observed, as the δ13C 1 and δ13C 2 values of the Longmaxi Formation become more positive toward the thrust-faulted folds developed in the southern CZ blocks. Highlights • Study presents the systematic analysis of the shale gas geochemistry in the CZ blocks. • Isotopic reversals resulted from secondary effects at high-maturity and are restricted to closed-system shale. • Details of geographic variation of carbon isotope ratios have been discussed. [ABSTRACT FROM AUTHOR]

The Lower Silurian Longmaxi Formation marine shales are the main shale gas reservoirs in the Sichuan Basin, SW China. The present study analyzes the characteristics of the Longmaxi shales using samples selected from wells N1 and N2 in the Changning block, southern Sichuan Basin. Several methods, including X-ray diffraction (XRD), scanning electron microscopy (SEM), helium gas expansion and low pressure nitrogen (N 2 ) adsorption/desorption, were used to investigate the mineralogical composition, geochemical characteristics, pore structure and other characteristics of the shales. The total organic carbon (TOC) contents of the samples range from 0.8 to 6.429%, and the thermal maturity is at the overmature stage. Two wells are rich in quartz and clay, with the average contents of 39.4% and 29.6%, respectively. The Longmaxi shales have the specific surface area and total pore volume around 16.6 m 2 /g and 0.0165 mL/g, respectively. It is suggested that the TOC content contributes significantly to the average pore size, specific surface area and total pore volume, and the thermal maturity strongly influences the development of porosity, as does the mineralogical composition. Based on imagine analysis, we classify shale gas microreservoirs into three types: organic matter with microfractures, organic matter alone and organic matter with mineral pores (interparticle pores (InterP pores) and intraparticle pores (IntraP pores)). The first type is the best for shale gas exploitation. The second type and the type of organic matter with InterP pores are better, while the type of organic matter with IntraP pores is almost useless. The analysis results show that the microreservoirs of well N1 mainly contain the type of organic matter with InterP pores, while the microreservoirs of well N2 are dominated by the type of organic matter with InterP pores and the type of organic matter with microfractures. Combing all the analysis results and their influencing factors, we consider that well N2 is more favorable for gas production than well N1. [ABSTRACT FROM AUTHOR]

Based on element geochemical and total organic carbon (TOC) analyses of core samples from the Silurian Longmaxi Formation black shales in the Sichuan Basin, this study tried to figure out the temporal changes of palaoenvironmental settings for the shale deposition. The redox-sensitive element ratios, such as U/Th, V/Sr, V/Cr, Ni/Co and V/(V + Ni) are useful indicators to define the redox condition of marine black shale deposition. Element geochemical analysis of Longmaxi Shale samples taken from well W201 and Z106 in the southern Sichuan Basin shows that the organic-rich shales at the bottom of the Longmaxi Formation were deposited in an anoxic environment, while the upper part organic-poor shales were deposited in an oxic environment. Meanwhile, the sedimentary and paleontological characteristics show that pyrite and microfossils are concentrated mainly in the lower organic-rich black shales, indicating also an anoxic environment. All these geochemical, sedimentary and paleontological criteria indicate a paleoenvironmental change from bottom anoxic to middle and upper dysoxic/oxic conditions for the Longmaxi Formation shales. Furthermore, geochemical indicators should be combined with sedimentary and paleontological features in the study of palaeoenvironment conditions for shale deposition. [ABSTRACT FROM AUTHOR]

The presence of shale gas has been confirmed in almost every marine shale distribution area in North America. Formation conditions of shale gas in China are the most favorable for marine, organic-rich shale as well. But there has been little research focusing on shale gas in Qiangtang Basin, Qinghai-Tibet Plateau, where a lot of Mesozoic marine shale formations developed. Based on the survey results of petroleum geology and comprehensive test analysis data for Qinghai-Tibet Plateau, for the first time, this paper discusses characteristics of sedimentary development, thickness distribution, geochemistry, reservoir and burial depth of organic-rich shale, and geological conditions for shale gas formation in Qiangtang Basin. There are four sets of marine shale strata in Qiangtang Basin including Upper Triassic Xiaochaka Formation (T3 x), Middle Jurassic Buqu Formation (J2 b), Xiali Formation (J2 x) and Upper Jurassic Suowa Formation (J3 s), the sedimentary types of which are mainly bathyal-basin facies, open platform-platform margin slope facies, lagoon and tidal-flat facies, as well as delta facies. By comparing it with the indicators of gas shale in the main U.S. basins, it was found that the four marine shale formations in Qiangtang Basin constitute a multi-layer distribution of organic-rich shale, featuring a high degree of thickness and low abundance of organic matter, high thermal evolution maturity, many kinds of brittle minerals, an equivalent content of quartz and clay minerals, a high content of feldspar and low porosity, which provide basic conditions for an accumulation of shale gas resources. Xiaochaka Formation shale is widely distributed, with big thickness and the best gas generating indicators. It is the main gas source layer. Xiali Formation shale is of intermediate thickness and coverage area, with relatively good gas generating indicators and moderate gas formation potential. Buqu Formation shale and Suowa Formation shale are of relatively large thickness, and covering a small area, with poor gas generating indicators, and limited gas formation potential. The shale gas geological resources and technically recoverable resources were estimated by using geologic analogy method, and the prospective areas and potentially favorable areas for Mesozoic marine shale gas in Qiangtang Basin are forecast and analyzed. It is relatively favorable in a tectonic setting and indication of oil and gas, shale maturity, sedimentary thickness and gypsum-salt beds, and in terms of mineral association for shale gas accumulation. But the challenge lies in overcoming the harsh natural conditions which contributes to great difficulties in ground engineering and exploration, and high exploration costs. [ABSTRACT FROM AUTHOR]

A continuously cored well covering the Carboniferous-Permian Benxi, Taiyuan, and Shanxi formations in the eastern Ordos Basin provides a rare window into environmental conditions of the marine-continental transitional strata. Integration of petrographic, mineralogical, and high-resolution geochemical data allows marine-continental investigating the depositional environment, organic abundance, detrital influx, paleoclimate, paleo-water salinity, and paleoredox conditions of transitional facies. The marine-continental transitional strata in the Upper Carboniferous to Lower Permian consist of complex interbedding of sandstone, shale, coal and limestone. TOC contents display a considerable change in the vertical direction, with high TOC content in coal, moderate TOC in shale, low TOC content in limestone and no noticeable TOC enrichment in sandstone. The Upper Carboniferous Benxi Formation is dominated by marine facies then changing into transitional facies. The Lower Permian Taiyuan Formation is characterized by multiple alternation of marine and transitional facies. Marine limestones are characterized by low detrital influx proxies, whereas transitional shales show high detrital influx input and oxic environment. The Lower Permian Shanxi Formation is a typical marine-continental transitional depositional system, which is characterized by complex interbedding of shales, sandstones and coals. Sandy intervals were deposited in deltaic and tidal flat environment and characterized by high Ti and Al content, low TOC (0.09–0.97%, avg. 0.31%), relatively low U/Th (0.11–0.32, avg. 0.17), showing limited influence of seawater. Shale intervals were deposited in a lagoonal environment with high TOC (0.94–40.64%, avg. 5.43%), Sr/Ba and trace elemental proxies values (U/Th, 0.18–3.27%, avg. 0.44%; Mo EF , 0.95–32.3, avg. 8.56; U EF , 0.67–15.17, avg. 2.53). This study shows that high-resolution geochemical characteristics of elements could be reliable indicators for sedimentary facies analysis, and hence could provide broader implications for utilizing trace element geochemistry from marine-continental transitional periods in which sedimentary environment changes frequently and organic-rich sediment accumulated under varied conditions. • A systematic sedimentological study was conducted on C-P transitional shales. • We establish a high-resolution paleoenvironmental profile of transitional strata. • Depositional models were established for of the C-P transitional facies. • Geochemical characteristics of elements useful for sedimentary facies analysis [ABSTRACT FROM AUTHOR]

Although the annual production of shale gas in China was 13 × 10 8 m 3 in 2014, a systematic study on geochemical and isotopic characteristics of these unconventional gases has not been well addressed. In the present study, almost all shale gas samples available in China, including marine shale gas from the Wufeng-Longmaxi Formation in the Sichuan Basin (O 3 w–S 1 l) and terrestrial shale gas from Chang 7 Member (T 3 y 7 ) in the Ordos Basin, were collected and analyzed for their geochemical and isotopic compositions. The shale gas from the Wufeng-Longmaxi Shale is dry gas with an average methane content of 98.38% and records a highest content of CH 4 in the world (99.59%), which is consistent with the very high thermal maturity levels of the gas shales that have equivalent vitrinite reflectance (EqVRo) values between 2.4 and 3.6%. The δ 13 C 1 values are correspondingly heavy and record a heaviest δ 13 C 1 values (−26.7‰) for the shale gases found in the world as well. The average values of δ 13 C 1 , δ 13 C 2 and δ 13 C 3 for the Wufeng-Longmaxi shale gas are −31.3‰, −35.6‰, and −47.2‰, respectively, displaying a complete carbon isotopic reversal (i.e., δ 13 C 1 > δ 13 C 2 > δ 13 C 3 ). δ 2 H CH4 and δ 2 H C2H6 has an average value of −148‰ and −173‰, respectively, also yielding a hydrogen isotopic reversal (i.e., δ 2 H CH4 > δ 2 H C2H6 ). The Chang 7 shale has an average TOC content of 13.81% with vitrinite reflectance (VRo) values between 0.7 and 1.2%. The Chang 7 shale gas is wet gas with an average methane content of 84.90% and is rich in heavy gaseous hydrocarbons (C 2 –C 5 ). The respective values of δ 13 C 1 , δ 13 C 2 and δ 13 C 3 are −48.7‰, −36.4‰ and −31.3‰, displaying a positive carbon isotopic distribution pattern (i.e., δ 13 C 1 < δ 13 C 2 < δ 13 C 3 ). The average δ 2 H CH4 , δ 2 H C2H6 and δ 2 H C3H8 values are −256‰, −244‰ and −188‰, respectively, and are characterized by a positive distribution pattern (i.e., δ 2 H CH4 < δ 2 H C2H6 < δ 2 H C3H8 ). The differences in gas wetness and carbon and hydrogen isotopic distribution patterns between the shale gases from the Wufeng-Longmaxi and Chang 7 shale are attributed to variations in thermal maturity levels. CO 2 is present in low content in both the Wufeng-Longmaxi and Chang 7 shale gases, mostly less than 1%. δ 13 C values for the CO 2 in the Wufeng-Longmaxi Formation are between 8.9 and −9.2‰, indicating an inorganic origin from the cracking of carbonate mineral in the shales under high temperatures. In contrast, δ 13 C values of the CO 2 in the Chang 7 shale gas range from −8.2 to −22.7‰, indicating an organic origin from the thermal degradation of organic matter. Helium in both the Wufeng-Longmaxi and Chang 7 shale gases is dominantly of curst origin in terms of their R/Ra ratios that vary from 0.01 to 0.08. Positive carbon isotopic distribution pattern is typical of primitive thermogenic gas. However, it can be converted into complete or partial carbon isotopic reversal patterns due to secondary alteration. The causes that yield carbon isotopic reversal include (1) mixing of gases with the same source but different thermal maturity levels; (2) secondary cracking of oil or wet gas; (3) formation water-involved reactions; (4) gas diffusion; and (5) carbon isotope exchange between alkane gases at high temperature. Among them, carbon isotopic exchange between alkane gases at high temperature is a key factor. Nine plots have been drawn based on the shale gases from China, USA and Canada. Among them, the plot of δ 13 C 2 versus wetness demonstrates a “lying-S” shape with two inflection points on the gas wetness axis. The wetness value of 1.4% represents a critical point from pyrolytic gas (primary cracking gas) to cracking gas (secondary cracking gas) and whereas the wetness value of 6% marks the end of oil generation. On the diagram of wetness versus δ 13 C, shale gases with wetness values greater than 1.6% are characterized by positive carbon isotopic distribution pattern, whereas a complete or partial carbon isotopic reversals are observed for shale gases with wetness values less than 1.6%. [ABSTRACT FROM AUTHOR]

In order to understand the paleoenvironment of the Early Cambrian black shale deposition in the western part of the Yangtze Block, geochemical and organic carbon isotopic studies have been performed on two wells that have drilled through the Qiongzhusi Formation in the central and southeastern parts of Sichuan Basin. It shows that the lowest part of the Qiongzhusi Formation has high TOC abundance, while the middle and upper parts display relative low TOC content. Redox-sensitive element (Mo) and trace elemental redox indices (e.g., Ni/Co, V/Cr, U/Th and V/(V + Ni)) suggest that the high-TOC layers were deposited under anoxic conditions, whereas the low-TOC layers under relatively dysoxic/oxic conditions. The relationship of the enrichment factors of Mo and U further shows a transition from suboxic low-TOC layers to euxinic high-TOC layers. On the basis of the Mo-TOC relationship, the Qiongzhusi Formation black shales were deposited in a basin under moderately restricted conditions. Organic carbon isotopes display temporal variations in the Qiongzhusi Formation, with a positive excursion of δ 13 C org values in the lower part and a continuous positive shift in the middle and upper parts. All these geochemical and isotopic criteria indicate a paleoenvironmental change from bottom anoxic to middle and upper dysoxic/oxic conditions for the Qiongzhusi Formation black shales. The correlation of organic carbon isotopic data for the Lower Cambrian black shales in different regions of the Yangtze Block shows consistent positive excursion of δ 13 C org values in the lower part for each section. This excursion can be ascribed to the widespread Early Cambrian transgression in the Yangtze Block, under which black shales were deposited. [ABSTRACT FROM AUTHOR]

The unique self-generation and self-storage characteristics of shale gas allow for its geochemical characteristics to better reflect the gas generation process inside the original rock under geological conditions. Based on a systematic analysis of 541 typical shale gas components and stable isotope compositions worldwide, this review provides an in-depth elucidation of the geochemical characteristics of Silurian shale gas in the Sichuan Basin, including an explanation of its special isotope anomalies. The over-mature Longmaxi Formation shale gas is dominated by alkane gas components (> 99%), which almost entirely (98.7%) consist of methane (CH 4). The distinctive characteristics of high CH 4 and low C 2+ contents result in extremely low wetness of <0.6%, which is typical of dry gas. In view of the sapropelic kerogen origin, the Longmaxi shale gas belongs to late-mature thermogenic gases (LMT). Geochemical anomalies of Longmaxi shale gas mainly refer to abnormally enriched δ13C 1 values and full reversal, resulting in deviations in carbon isotope composition and light hydrocarbon data for shale gas in the Changning-Zhaotong and Fuling areas, unlike the slightly less thermally evolved Weiyuan area. Noble gases of the Longmaxi shale gas exhibit characteristics of crustal origin and marine carbonate, and the light hydrocarbons in Longmaxi shale gas have been seriously cracked and destroyed, and the residual fraction is more reflective of its chemical stability. At extremely high maturity, the Rayleigh fractionation effect of ethane and the involvement of inorganic material in redox reactions are important causes of isotopic anomalies in Longmaxi shale gas. The variation of δ13C 1 and δ13C 2 values of shale gas in the producing area suggests that fluid-rock interactions related to CO 2 may have occurred, but not to a significant degree, and the cumulative effects of diffusion are similarly observed. The δ13C 2 values and magnitude (δ13C 1 − δ13C 2) of Weiyuan shale gas are negatively and positively correlated with daily production, respectively, which proves that the methane in shale gas mainly comes from ethane cracking during the over-maturation stage. By comparing with typical coal-derived gas, new discriminative trend lines in the reversal zone (δ13C 1 > δ13C 2) have a certain degree of credibility and applicability. Unraveling the geological processes that led to the formation of geochemical anomalies in the Longmaxi shale gas can provide valuable insights for in-depth analysis of the late-stage gas generation. • Geochemical characteristics of Longmaxi shale gas were compared and analyzed. • Potential pathways for rational explanation of geochemical anomalies were proposed. • New discriminative trend lines were drawn in the reversal zone (δ13C 1 > δ13C 2) to improve the genesis identification. [ABSTRACT FROM AUTHOR]

Oil and gas discoveries within Proterozoic-Cambrian strata and the majority of shale gas production occurs in relatively stable tectonic regions and characterised by moderate thermal maturity (R o °<°2.5%). The Sinian–Silurian gas resource located in China's Sichuan Basin is a definitely different example of a concurrent conventional and unconventional gas system within a tectonically complicated basin and sourced from overly-mature organic shales (R o °>°2.5%). The system comprises two components, namely a conventional Sinian–Cambrian dolomite-hosted gas resource and an unconventional Cambrian-Silurian shale gas deposit, both represent trillion cubic meter accumulations. The migration-accumulation type Sinian–Cambrian gas system, is a result of numerous processes, including (1) paleo-high trapping within a relatively stable tectonic setting, (2) appropriate source materials located in a paleo-rift trough, (3) large-scale dolomite grainstone reservoirs located near the paleo-high, (4) adequate gas produced from in-situ crude oil cracking, and, (5) gypsum-salt and shale cap rock preservation. The self-contained source-reservoir Cambrian–Silurian shale gas system, is localized by deepwater organic-rich shelf facies, characterized by high silicon and calcium contents. The recent discovery of these two massive gas fields in old and over-matured sedimentary strata, has effectively extended the upper maturity limit of R o over 3.0%, which may indicate the efficacy of broadening current natural gas exploration areas, thus potentially increasing global natural gas resources significantly. Furthermore, the discovery may spark interest in natural gas exploration in widely distributed old strata, thus encouraging co-development of conventional and unconventional petroleum accumulations. [ABSTRACT FROM AUTHOR]