Lower Paleozoic Marine Shales Research Articles

The organic petrology of vitrinite-like maceral in the Lower Paleozoic shales: Implications for the thermal maturity evaluation

Vitrinite-like maceral (VLM) is a type of autochthonous, synsedimentary, dispersed organic matter, which is ubiquitous in many Lower Paleozoic marine shales. The VLM reflectance has been used as an alternative tool to evaluate the thermal maturity of pre-Devonian marine sediments lacking a classical vitrinite, however, the existing knowledge about its optical properties and reflectance characteristics is still relatively limited. In this study, the optical properties of VLM were examined by means of organic-petrological methods applied to a series of naturally and artificially matured VLM-rich shales samples and their reflectance crossplots. The strong positive correlation between the true maximum reflectance (Rmax) and bireflectance of VLM indicates the increasing anisotropy of VLM with increasing thermal maturity. VLM shows a linear coalification path in the studied shales. It displays biaxial neutral features in the samples with Rmax ≤ 2%, but shows obvious optically biaxial negative characteristics in the samples with Rmax > 2%. The shape of VLM reflectance indicating surface (VLMRIS) gradually becomes oblate with increasing maturity. These results indicate that VLM exhibits appearance and optical properties similar to vitrinite, and its reflectance can be used as a reliable indicator for thermal maturity evaluation. The equivalent vitrinite reflectance (EqVRo) values, which were calculated based on the mean measured maximum reflectance of VLM (VLMR¯max), evidence that the Niutitang Formation shales from China and Alum shales from Denmark are post-over mature, and the Yurtus Formation shales in Tarim Basin and the Alum shales from Sweden are still within the oil window.

Geological Characteristics and Controlling Factors of Deep Shale Gas Enrichment of the Wufeng-Longmaxi Formation in the Southern Sichuan Basin, China

Abstract To identify the factors controlling high-quality deep shale gas reservoirs and the exploration and development potential of the Lower Paleozoic marine shale in the Sichuan Basin, the sedimentary environment of deep shale was comprehensively analysed using core thin sections, scanning electron microscopy, gamma ray spectrometry logging, and elemental logging data. In addition, the geological conditions of deep shale gas accumulation and the effect of tectonic processes on the preservation conditions are discussed based on the experimental data of mineral composition analysis, geochemical features, and reservoir spatial characteristics. (1) The sedimentary environment changes from an anoxic water environment to an oxygen-rich oxidizing environment from bottom to top in the Wufeng-Longmaxi Formation in southern Sichuan. The deep shale gas reservoir shows overpressure and rich gas characteristics, namely, high formation pressure (2.0~2.2), high porosity (20%~55%), and high gas content (4.0~5.0 m3/t). (2) The favourable sedimentary environment has a higher hydrocarbon generation potential and deposits of rich organic matter and siliceous particles. During the hydrocarbon generation process, the rich organic matter generates a large number of organic pores and a large specific surface area, which provides the main reservoir and adsorption space for free and adsorbed shale gas. A large number of biogenic siliceous particles provide a solid rock support framework for the shale reservoir, thereby maintaining excellent reservoir physical properties. (3) Late and small stratigraphic uplifts result in a short shale gas escape time and favourable preservation conditions. Additionally, the small-scale faults and a high-angle intersection between the fracture strike and the geostress direction are conducive to the preservation of shale gas. (4) A high formation pressure coefficient, a sedimentary environment rich in organic siliceous deep-water continental shelf microfacies, and a relatively stable tectonic structure are conducive to the accumulation of deep shale gas.

Pore Characteristics and Gas Preservation of the Lower Cambrian Shale in a Strongly Deformed Zone, Northern Chongqing, China

The Lower Paleozoic marine shale in southern China has undergone several strong tectonic transformations in an extensive region outside the Sichuan Basin. Although some shale strata underwent strong deformation, they still contain a significant amount of shale gas. The gas preservation mechanism in the strongly deformed shale has become the focus of attention. In this paper, the Lower Cambrian gas-bearing shale samples with a strong deformation taken from an exploration well in northern Chongqing, China, were investigated on their pore types and structure, with the aim to reveal the reason for the gas preservation. The pore types of the Lower Cambrian shale are dominated by microfractures and interparticle (interP) pores occurring mainly between clay minerals and between organic matter (OM) and clay minerals, while pores within OM that can be observed by FE-SEM (field emission-scanning electron microscopy) are rare. The shale has a low porosity, with an average of 1.56%, which is mainly controlled by the clay mineral content. The adsorption experiments of low pressure N2 (LPNA) and CO2 (LPCA) indicate that the shale is rich in micropores and small mesopores (<2–3 nm) provided mainly by OM, but mesopores with a size range of 3–50 nm are underdeveloped. The shale, as revealed by LPNA data, has dominant slit-like or plate-like pores and an obvious low-pressure hysteresis (LPH), indicating a low gas diffusion. The deformed shale samples with a removal of OM by oxidation and their isolated kerogen further indicate that the LPH is completely related to OM, without any relationship with minerals, while an undeformed shale sample, taken from another well for a comparison, has no obvious LPH for both of its OM-removed sample and kerogen. Based on a comprehensive analysis of the relative data, it is suggested that the nanopores related to OM and clay minerals in the shale were significantly altered owing to the deformation, with a result of the pores being squeezed into the slit-like shape and converted into micropores. This extraordinary pore structure of the shale formed during the deformation process should be the main preservation mechanism of shale gas.

Thermal evolution behavior of the organic matter and a ray of light on the origin of vitrinite-like maceral in the Mesoproterozoic and Lower Cambrian black shales: Insights from artificial maturation

The overmature Precambrian to Lower Paleozoic marine shales from China contain relatively simple organic matter (OM) composition, which is dominated by in-source solid bitumen (i.e., solid bitumen in the hydrocarbon source rocks). The thermal evolution behavior of the original OM and the determination of thermal maturity in the Precambrian to Cambrian marine shales have been challenging for decades. The vitrinite-like maceral (VLM) is widely present in these marine shales, and its origin is still unknown. To address these issues, the immature Proterozoic Xiamaling shales from China and the immature Cambrian Alum shales from Sweden, and a Chinese immature Carboniferous coal were heat-treated at temperature range of 300 °C to 550 °C. The carbonized residue of the artificially matured samples was examined for their morphological and reflectance variation, and the results were compared with data on the other overmature natural shales from China and Sweden.OM components are similar in the Xiamaling and Alum immature oil shales, consisting of filamentous algae, matrix bituminite, bituminite, VLM and liptodetrinite, and rare thucholites are present in the Xiamaling shales. The algal-derived OM decomposed gradually due to hydrocarbon generation at 300–350 °C. OM is mainly composed of the in-source solid bitumen in the artificially heated shales after 350 °C, similar to the overmature Precambrian to Cambrian natural shales, and the in-source solid bitumen gradually loses its mass with increasing thermal maturity. The in-source solid bitumen is derived from the thermal cracking of the retained oil or the direct conversion of algal-derived liptinite macerals (e.g., the bituminite) or their mixture. VLM in the Xiamaling oil shales can not be observed after 350 °C, but VLM is still present in the Alum oil shales. It can be inferred that there is a different source of VLM in these shales, and VLM in the Xiamaling oil shales contains more volatile material. The VLM in the Xiamaling shales may be biodegradation products of liptinites under anoxic environments. The origin of VLM in the Cambrian Alum shales requires further study to be verified, although it is certain that graptolites are not its sources. The reflectance of in-source solid bitumen (SBRo) increases with heat-treated temperature in both the Xiamaling shales and the Alum shales, but at different rates, which may be due to the difference of the original kerogen composition in these shales. VLM reflectance (VLMRo) and SBRo in sections perpendicular to bedding can be used to determine the maturation level of the Precambrian-Cambrian sediments. Their relation to equivalent vitrinite reflectance (EqVRo) can be expressed by the following equations: EqVRo = 1.07 × VLMRo – 0.18, EqVRo = 0.87 × SBRo + 0.25 (in the Precambrian sediments) and EqVRo = 1.15 × SBRo + 0.01 (in the Cambrian sediments).

Alteration of organic macerals by uranium irradiation in lower Paleozoic marine shales

Measuring the degree of organic matter (OM) alteration caused by uranium (U) irradiation is important in the effective evaluation of the hydrocarbon potential and thermal maturity of U-rich source rocks. This study investigates OM alteration in the Baltoscandian U-rich, lower Paleozoic Alum shale obtained from three research wells in the thermally immature parts of eastern Sweden and western Estonia. The results show a marked increase in the proportion of refractory, non-generative organic carbon (NGOC) in the U-rich shale. Fluorescence spectrometry of unicellular alginites and lamalginites show a reduction of up to 95.6% in fluorescence relative intensity (RI) with increase in U content from 29 to 401 ppm. Fluorescence spectra of the liptinites exhibit a marked “red shift” as expressed by increase in red(R)/green(G) quotients. This change in fluorescence properties of the liptinites is associated with up to 77.6% decrease in hydrogen index (HI) and hence loss of hydrocarbon generation potential. Furthermore, organic molecules show significant loss of aromatic moieties as well as aliphatic constituents resulting in a more condensed macromolecular structure. The measured random reflectance of solid bitumen (BRo) appears to be significantly elevated in micro scale proximity to the U-containing minerals. The heterogeneous distribution of U-containing minerals and the contact with solid bitumen attributes to the wider range of BRo values and lead to the overall increase in mean BRo in samples with high U contents. In contrast, Ro values of zooclast macerals (GRo, e.g., graptolite, chitinozoans and vitrinite-like fragments) appear to be less influenced by U irradiation and hence are a more reliable maturity indicator in U- rich lower Paleozoic shales.

Characteristics of pore structures from the Lower Paleozoic shale gas reservoirs in northern Guizhou, South China

Pore structure in shale is an important factor influencing the storage capacity of a shale gas reservoir and the effect of shale gas development. Taking the core and outcrop shale samples from the Lower Cambrian Niutitang Formation and Lower Silurian Longmaxi Formation as the object of the research, combined with the scanning electron microscope, high pressure mercury injection, CO2 and N2 gas adsorption experiments, we investigated the porosity, pore types, pore structure, and pore size distribution of the Lower Paleozoic shale gas reservoirs in northern Guizhou, South China. The results indicated that there are developed various genetic types of micro-nano pores in the Lower Paleozoic marine shale in northern Guizhou, which provide the main reservoir spaces for shale gas. The porosity of the Lower Paleozoic shale in northern Guizhou is 1.30%–13.37% in range, and the average is 4.56%. The inter-granular pore, organic matter pore and intra-granular pore are most common. Micropore (<2 nm) and mesopore (2–50 nm) are the main reservoir storage space for shale gas. The specific surface area of micropore plus mesopore in the Lower Paleozoic shale accounts for 94.3% of the total specific surface area, and their pore volume accounts for 59.1% of the total pore volume in northern Guizhou. The pore size of the Lower Paleozoic shale is mainly distributed in 0.4–0.7 nm, 3–10 nm and 0.05–200 μm. The pore structure is the parallel-plate pore with slit shape, two-ends-opened tube pore and ink-bottle shape pore. There are significant differences in the porosity and pore size between the Longmaxi Formation shale and the Niutitang Formation shale. The average porosity and average pore size of the Longmaxi Formation shale is 6.4% and 4.71 nm, while the Niutitang Formation shale is 5.3% and 4.23 nm, respectively. The pore structure of the Lower Paleozoic shale gas reservoir is mainly influenced by organic matter abundance, thermal maturity, mineral composition of shale. The porosity and micropore volume of shale show an increasing trend, with the increase of total organic carbon content and quartz content. The porosity and pore volume of shale have a decreasing trend, with the increase of thermal maturity level and clay mineral content.

Developmental characteristics and controlling factors of natural fractures in the lower paleozoic marine shales of the upper Yangtze Platform, southern China

This work elucidates the developmental characteristics and controlling factors of natural fractures, and their effects on the shale gas content in the lower Paleozoic marine shales of the upper Yangtze Platform, southern China. These objectives have been achieved by systematic observations and descriptions of fractures in outcrops and drilling cores, as well as experimental tests on samples from the corresponding fractured intervals. The types of natural macro-fractures observed in both the Niutitang and Wufeng-Longmaxi shales mainly include vertical tension fractures, high-angle shear fractures, bed-parallel slip fractures and bedding fractures, with bedding fractures accounting for the largest proportion. In addition, Field Emission-Scanning Electron Microscopy (FE-SEM) images show that interlayer, inter-particle, intra-particle and organic matter-associated fractures are the primary types of micro-fractures. Tectonism is one of the dominant factors in fracture development, but other factors also have a strong influence, such as TOC content, mineral composition and shale-bed thickness. Under similar tectonic settings, the development of fractures is mainly influenced by the TOC content. For the Wufeng-Longmaxi shale, fracture abundance is positively correlated with the TOC content. However, the TOC content in Niutitang shale displays a positive correlation with fracture density only when the TOC content is less than 6%; when the TOC content is greater than 6%, the correlation is shown to be negative. Shale with higher quartz or lower clay contents exhibits greater fracture development. Furthermore, the shale-bed thickness has a negative influence on the fracture development, which can be essentially attributed to the change in mineral composition of shale. Natural fractures provide reservoir spaces for free gas and are favorable for the desorption of adsorbed gas; therefore, the better shale fractures are developed, the greater the gas content will likely be.

Fractureability evaluation of shale gas reservoirs

ABSTRACT There are abundant shale gas resources in the Lower Paleozoic marine organic shale strata of the upper Yangtze region, South China. However, affected by multi-period tectonic activities, leading to poor exploitation of the Lower Paleozoic marine shale gas in the complex tectonic zone. Therefore, this study proposes fracturability index (FI) based on shale brittleness, fracture toughness, and stress decay rate. Therefore, this study combines logging data and rock mechanics experiments to obtain the rock mechanics parameters of the Fenggang block shale reservoir. Based on Young’s modulus, fracture toughness and critical strain energy release rate, combined with the analytic hierarchy process, the shale fracturability index is proposed to guide the exploration and development of shale gas. The fracturability index of the Longmaxi Formation shale in the study area is 0.34 ~ 0.72. The fracturability of the middle and lower part of the Longmaxi Formation shale is obviously better than that of the upper part. In general, shale reservoirs with high brittleness index, low fracture toughness, and low critical strain energy release rate have high fracturability.

The reservoir characteristics of marine shale and its effect on the adsorption of methane in Northern Guizhou

The reservoir characteristics of the Lower Paleozoic marine shale in Fenggang block of northern Guizhou are evaluated from three aspects: gas-bearing characteristics, petrological characteristics and reservoir space by a series of experimental data. The effect of total organic carbon content, kerogen type and clay mineral content on shale adsorption capacity is discussed. The results show that the reservoir characteristics of the Wufeng-Longmaxi Formation shale in the study area are conducive to the enrichment of shale gas. In the case of quantitative clay minerals, the chlorite content has a significant adverse effect on the methane adsorption of the samples. The shale gas methane adsorption has an excellent increasing trend with the increase of total organic carbon content. The type II1 organic matter is more conducive to the adsorption of methane than the type I organic matter.

Structural evolution of organic matter and implications for graphitization in over-mature marine shales, south China

Abstract To characterize the degree of organic matter graphitization in the over mature lower Paleozoic marine shales from South China, a suite of kerogen samples covering different maturity (Ro% ranging from 1.2% to 4.2%) were analyzed by Laser Raman microprobe (LRM), Transmission electron microscope (TEM) and Fourier transform infrared spectroscopy (FTIR) techniques. Chemical structures and related major changes caused by thermal evolution history were systematically discussed. The results indicate that with the thermal maturity increasing, the aliphatic side chains fall off gradually, and the aromatic rings increase continuously. The ordered structure of shales continues to enhance, leading to the increasing of graphitization degree. The parameters of LRM (i.e. position of G and D bands, peak position difference (RBS), full width at half maximum (FWHM) and intensity ratio (ID/IG)) highlight the “turning point” at maturity level around RmcRo% = 3.5%, which represents the chemical structure jump of the kerogen. This chemical structure jump can be characterized by the continuous decreasing of amorphous carbon before the RmcRo% exceeded 3.5% and the sharp increasing degree of aromatic conjugation after that point. TEM analysis indicates that the carbon layers of shale samples with RmcRo% exceeds 3.5% show better ordering and continuity than that of low maturity shale samples. The FTIR analysis suggests that there are relatively high aromatics C C chains and very few aromatic C-H chains in the high maturity samples. This critical chemical structure jump at RmcRo% = 3.5% could be interpreted as the structure of organic matter begins to transform from amorphous carbon to crystalline graphite in shales. Due to the increasing degree of graphitization, graphitized shale is characterized by stable chemical structure, condensed and orderly carbon layer constructure, and ultra-low resistivity.

Overpressure generation and evolution in Lower Paleozoic gas shales of the Jiaoshiba region, China: Implications for shale gas accumulation

Abstract Overpressured shale gas plays have been found in the Lower Paleozoic marine shales of Jiaoshiba region in the Sichuan basin, China. The black shales from the Upper Ordovician Wufeng Group (O3w) and the lower part of Lower Silurian Longmaxi Group (S1l) are the producing reservoirs. Overpressure is widespread in the O3w-S1l shales with the pressure coefficient up to 1.74. Fluid inclusion microthermometric and Raman spectroscopic techniques, PVT and basin modeling are used to investigate overpressure generation and evolution in the O3w-S1l shales. The results show that thermocatalytic dry gas generation is the main genetic mechanism for overpressure development in the O3w-S1l shales with specific characteristics as follows: (1) the maximum burial depth of overpressured shales is more than 6200 m without anomalously low density and high primary porosity according to wireline log and core data; (2) the over-mature O3w-S1l shales with the mean TOC values ranging from 3.36 wt% to 4.48 wt% and the vitrinite reflectance values of 2.7%–2.9% Ro determined by kerogen FTIR (Fourier transform infrared spectroscopy) characteristics, has excellent potential to produce dry gas; (3) overpressured reservoirs are characterized by high gas saturations, and the pressure coefficients positively correlate with gas saturation; (4) the abnormally high pressures recorded in the fluid inclusions are coincident with high homogenization temperatures, which is supportive of overpressure occurring during dry gas generation and provides convincing in-situ evidence for gas generation overpressuring. The calculated pore-fluid pressures for methane inclusions within the maximum buried O3w-S1l shales are approximately 90.3–139.4 MPa, suggesting that gas generation produced a maximum pressure gradient of 23.1 MPa/km, which is equivalent to the lithostatic magnitudes. The overpressure evolution in the O3w-S1l shales is noticed to have evolved through four stages: a rapidly increasing overpressure caused by thermocatalytic gas generation (>145-85 Ma), a rapid pressure release (85-61Ma), overpressure preservation (61-20 Ma), and a relatively slow pressure release (20 Ma - present). During post-generation evolution (85 Ma - present) of the O3w-S1l shales, both the overpressure and pressure coefficients decreased with time due to the intensive tectonic uplifts and denudation, and approximately 19.0%–28.5% of the initial total gas content was continuously released until the present-day overpressure state. The study of overpressure evolution in the O3w-S1l shales provides basic information for the further study of the conversion between adsorbed gas and free gas, and the method and technique used in this study to stress the overpressure generation and evolution may be generally applied to other overpressured or normally pressured shale gas systems.

Pore characteristics of shale gas reservoirs from the Lower Paleozoic in the southern Sichuan Basin, China

Data was acquired from both the drillings and core samples of the Lower Paleozoic Qiongzhusi and Longmaxi Formations' marine shale gas reservoirs in the southern Sichuan Basin by means of numerous specific experimental methods such as organic geochemistry, organic petrology, and pore analyses. Findings helped determine the characteristics of organic matter, total porosity, microscopic pore, and pore structure. The results show that the Lower Paleozoic marine shale in the south of the Sichuan Basin are characterized by high total organic carbon content (most TOC>2.0%), high thermal maturity level (RO = 2.3%–3.8%), and low total porosity (1.16%–6.87%). The total organic carbon content and thermal maturity level of the Qiongzhusi Formation shale are higher than those of the Longmaxi Formation shale, while the total porosity of the Qiongzhusi Formation shale is lower than that of the Longmaxi Formation shale. There exists intergranular pore, dissolved pore, crystal particle pore, particle edge pore, and organic matter pore in the Lower Paleozoic Qiongzhusi Formation and Longmaxi Formation shale. There are more micro-nano pores developed in the Longmaxi Formation shales than those in the Qiongzhusi Formation shales. Intergranular pores, dissolved pores, as well as organic matter pores, are the most abundant, these are primary storage spaces for shale gas. The microscopic pores in the Lower Paleozoic shales are mainly composed of micropores, mesopores, and a small amount of macropores. The micropore and mesopore in the Qiongzhusi Formation shale account for 83.92% of the total pore volume. The micropore and mesopore in the Longmaxi Formation shale accounts for 78.17% of the total pore volume. Thus, the micropores and mesopores are the chief components of microscopic pores in the Lower Paleozoic shale gas reservoirs in the southern Sichuan Basin.

Accumulation conditions of Lower Paleozoic shale gas from the southern Sichuan Basin, China

Based on the raw data of the organic-rich shale in the Lower Cambrian Qiongzhusi Formation and Lower Silurian Longmaxi Formation which were collected from the drilling core, we investigated the accumulation conditions of the Lower Paleozoic marine shale gas in the southern Sichuan Basin, China. The results indicate that the Qiongzhusi and the Longmaxi Formations' black shales in this region are mainly deposited in the deep water shelf sedimentary environment. Both the Qiongzhusi and Longmaxi Formations in the southern Sichuan Basin have great organic-rich shale thickness (mainly 50–300 m). The marine shales of the Qiongzhusi and the Longmaxi Formations are characterized by high total organic carbon contents (average TOC>2%), I–II1 kerogen types, highthermal maturity level (equivalent RO>1.9%), abundant rich brittle mineral (average > 50%), micro- and nanometer pore development, as well as high gas content of shale (average > 1.8 m3/t). All these features are favorable for marine shale gas generation and enrichment in the southern Sichuan Basin. Compared to the Barnett shale in North America, in which shale gas has been explored and developed successfully, it is suggested that the Lower Paleozoic in the southern Sichuan Basin would possess good conditions for shale gas accumulation. Therefore, the Qiongzhusi and the Longmaxi Formations are considered as potential targets for marine shale gas exploration, and favorable areas for shale gas enrichment are also purposed. The favorable areas for shale gas enrichment for the Qiongzhusi Formation in the southern Sichuan Basin are the Zhigong-Yibin, Changning-Gongxian, Jianwei-Muchuan, and Weiyuan areas. The favorable areas for shale gas enrichment for the Longmaxi Formation in the southern Sichuan Basin are the Longchang-Rongchang, Yibin-Luzhou-Changning, and Weiyuan areas.

Shale gas in China: Characteristics, challenges and prospects (I)

Abstract This paper mainly discusses the industrialization progress, “sweet spot” evaluation criterion, E&P technologies, success experiences, challenges and prospects of China's shale gas. Based on the geologic and engineering parameters of the Fuling, Changning and Weiyuan shale gas fields in the Sichuan Basin, this paper points out that China's shale gas has its particularity. The discoveries of super-giant marine shale gas fields with high evolution degree (R o =2.0%−3.5%) and ultrahigh pressure (pressure coefficient=1.3−2.1) in southern China is of important scientific significance and practical value to ancient marine shale gas exploration and development to China and even the world. It's proposed that shale gas “sweet spots” must be characterized by high gas content, excellent frackability and good economy etc. The key indicators to determine the shale gas enrichment interval and trajectory of horizontal wells include “four highs”, that is high TOC (>3.0%), high porosity (>3.0%), high gas content (>3.0 m 3 /t) and high formation pressure (pressure coefficient>1.3), and “two well-developed” (well-developed beddings and well-developed micro-fractures). It's suggested that horizontal well laneway be designed in the middle of high pressure compartment between the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation. The mode of forming “artificial shale gas reservoir” by “fracturing micro-reservoir group” is proposed and the mechanisms of “closing-in after fracturing, limiting production through pressure control” are revealed. Several key technologies (such as three-dimensional seismic survey and micro-seismic monitoring of fracturing, horizontal wells, “factory-like” or industrialized production mode, etc.) were formed. Some successful experiences (such as “sweet spot” selection, horizontal well laneway control, horizontal length optimization and “factory-like” production mode, etc.) were obtained. The four main challenges to realize large-scale production of shale gas in China include uncertainty of shale gas resources, breakthroughs in key technologies and equipment of shale gas exploration and development below 3 500 m, lower cost of production, as well as water resources and environment protection. It is predicted that the recoverable resources of the Lower Paleozoic marine shale gas in southern China are approximately 8.8×10 12 m 3 , among which the recoverable resources in the Sichuan Basin are 4.5×10 12 m 3 in the favorable area of 4.0×10 4 km 2 . The productivity of (200−300)×10 8 m 3 /a is predicted to be realized by 2020 when the integrated revolution of “theory, technology, production and cost” is realized in Chinese shale gas exploration and development. It is expected in the future to be built “Southwest Daqing Oilfield (Gas Daqing)” in Sichuan Basin with conventional and unconventional natural gas production.

Methane Adsorption Capacities of the Lower Paleozoic Marine Shales in the Yangtze Platform, South China

The adsorption capacities of the Lower Silurian Longamxi and Lower Cambrian Niutitang marine shales in the Yangtze Platform in China were investigated through methane adsorption experiments. The correlations between the adsorption capacities and major factors, e.g., total organic carbon (TOC) contents, thermal maturity, mineral composition, moisture content, pressure, and temperature, were discussed. The isosteric adsorption heat was calculated according to the temperature dependency of the methane adsorption isotherms. The results show that, under the temperature of 30 °C and pressure range of 0–12 MPa, the maximum adsorption capacity of the Longmaxi shales ranges between 0.47 and 3.08 m3/ton of rock and that of the Niutitang shales ranges between 1.59 and 7.43 m3/ton of rock. The Langmuir adsorption capacity varies from 0.54 to 3.84 m3/ton of rock for the Longmaxi shales and from 1.98 to 9.73 m3/ton of rock for the Niutitang shales. The TOC content shows a significantly positive correlation with the ads...

Geology, resource potentials, and properties of emerging and potential China shale gas and shale oil plays

This paper describes the geology of organic-rich shales in China, their resource potentials, and properties of emerging and potential China shale gas and shale oil plays. Marine, lacustrine, and coastal swamp transitional shales were estimated to have the largest technically recoverable shale gas resource (25.08 trillion cubic meters or 886 trillion cubic feet) and 25 to 50 billion barrels of technically recoverable shale oil resource. The Precambrian Sinian Doushantuo Formation to Silurian Longmaxi black marine shales mainly accumulated in the intrashelf low to slope environments in the Yangtze Platform in South China and in the Tarim Platform in northwest China. The marine shales in the Yangtze Platform have high maturity (Ro of 1.3%–5%), high total organic carbon (mainly [Formula: see text]), high brittle-mineral content, and have been identified as emerging shale gas plays. The Lower Paleozoic marine shales in the Upper Yangtze area have the largest shale gas potential and currently top the list as exploration targets. The Carboniferous to Permian shales associated with coal and sandstones were mainly formed in transitional depositional settings in north China, northwest China, and the Yangtze Platform in south China. These transitional shales are generally rich in clay with a medium level of shale gas potential. The Middle Permian to Cenozoic organic-rich lacustrine shales interbedded with thin sandstone and carbonate beds are sporadically distributed in rifted basins across China. Their main potentials are as hybrid plays (tight and shale oil). China shales are heterogeneous across time and space, and high-quality shale reservoirs are usually positioned within transgressive systems tract to early highstand systems tract intervals that were deposited in an anoxic depositional setting. For China’s shale plays, tectonic movements have affected and disrupted the early oil and gas accumulation, making tectonically stable areas more favorable prospects for the exploration and development of shale plays.

Effect of pore structure on methane sorption potential of shales

Samples from the lower Paleozoic marine shale and Mesozoic continental shale in the west of middle Yangtze region were taken to investigate the effect of pore structure characteristics on the methane sorption of shale using field emission scanning electron microscope (FE-SEM), low pressure N2 isotherm analysis and high pressure methane sorption analysis. A mass of organic matter pores (mostly with pore diameter less than 50 nm) have been found in the high thermal evolution marine shale rich in organic matter. The positive correlation between TOC, N2 BET surface areas and sorption capacity in shale indicate that micro-porosity associated with organic matter is the key factor controlling methane sorption capacity of high thermal maturity shale rich in organic matter. The development of organic matter pores was limited in the organically lean marine shale and continental shale due to the lower TOC content and lower thermal maturity respectively, and their reservoir space is composed of inorganic matter pores in 30 nm to 4.5 μm diameter. Providing bigger specific surface area for methane sorption, the pores within or between clay particles is an important factor to affect methane sorption capacity. With the increase of thermal maturity, the major pore system of shale reservoir changes from inorganic matter pores to organic matter pores, favorable for the improvement of methane sorption capacity of shale.

Indication of natural gas migration and accumulation by three-dimensional fluorescence characteristics of gas-field waters: A case study of the Permian-Triassic in the central-western Sichuan Basin

Abstract Permian-Triassic natural gas migration paths and accumulation patterns in the central-west Sichuan region have been studied by way of examining the three-dimensional shape, light intensity excitation and fingerprint characteristics of aromatic hydrocarbons fluorescence spectra of gas-field waters. The Permian-Triassic gas-field waters in the central-western Sichuan Basin have (condensate) gas reservoir characteristics, where three subclasses (base peak, double peak and odd peak, but mainly the stable type of base peak subclass) and seven types of three-dimensional fluorescence characteristics have been identified. Three-dimensional fluorescence characteristics of the waters of the Permian-Middle and Lower Triassic differ greatly from that of the Upper Triassic Xujiahe Formation. The former is mainly influenced by hydrocarbons from high to over mature Lower Paleozoic marine shales and the Upper Permian Longtan Formation coals, but the latter is mainly influenced by its own source rock maturity differences and organic matter type difference. Research on the three-dimensional fluorescence characteristics indicates that the Upper Permian and Middle to Lower Triassic reservoirs in the Moxi structure are predominately dominated by vertical migration and accumulation. Gas in the reservoirs below the Leikoupo Formation originates mainly from the Longtan Formation coals, while the Leikoupo Formation gas reservoir includes gas from a gypsum-salt rock section. Gas in the Xujiahe gas reservoir in the Pingluoba structure is mainly migrated from central-southern faults and the reservoirs have strong lateral heterogeneity.