Jinchuan Zhang

Natural gas potential of Neoproterozoic and lower Palaeozoic marine shales in the Upper Yangtze Platform, South China: geological and organic geochemical characterization

In this article, we describe the geological features of the Ediacaran (upper Sinian), lower Cambrian and lower Silurian shale intervals in the Upper Yangtze Platform, South China, and report on the gas potential of 53 samples from these major marine shale formations. Reflected light microscopy, total organic carbon (TOC) measurement, Rock-Eval, carbon isotope ratio analysis, thermovaporization gas chromatography (Tvap-GC), and open pyrolysis gas chromatography (open py-GC) were used to characterize the organic matter. Measured TOC in this research is normally >2% and averages 5%. TOC contents are roughly positively correlated with increasing geological age, i.e. lower Silurian shales exhibit generally lower TOC contents than lower Cambrian shales, which in turn commonly have lower TOC contents than Ediacaran shales. Kerogen has evolved to the metagenesis stage, which was demonstrated by the abundant pyrobitumen on microphotographs, the high calculated vitrinite reflectance (Ro = 3%) via bitumen reflectance (Rb), as well as δ13 C of gas (methane) inclusions. Pyrolysates from Tvap-GC and open py-GC are quantitatively low and only light hydrocarbons were detected. The lower Silurian shale generally exhibits higher generation of hydrocarbon than the lower Cambrian and Ediacaran shale. Cooles’ method and Claypool’s equations were used to reconstruct the original TOC and Rock-Eval parameters of these overmature samples. Excellent original hydrocarbon generation was revealed in that the original TOC (TOCo) is between 5% and 23%, and original S1+S2 (S1o+S2o) is ranging from 29 to 215 mg HC/g rock.

Paleoenvironment of Lower Silurian black shale and its significance to the potential of shale gas, southeast of Chongqing, China

Black shale is studied because of its economic value, paleoclimatic and paleogeographic significance. Due intensive development southeast of Chongqing, Longmaxi black shale, characterized by thickness in excess of 100 m, is becoming a location of concentrated research interest for shale gas exploration in China. The paleoenvironment, mineral composition, elements and reservoir characteristics of black shale of the Lower Silurian Longmaxi formation southeast of Chongqing were obtained by cores, outcrops, slices analysis, X-ray diffraction and X-ray fluorescence spectrum. The results show that Longmaxi black shale, including turbidite and suspended sediment, is deposited primarily in deep water. The sum of SiO2, Al2O3 and Fe2O3 content ranges from 73.82% to 90.54% by weight; quartz, feldspar and clay minerals are the dominant minerals in the rocks, ranging from 56% to 100%. Trace element contents of Mo (7.71 μg/g) and U (5.97 μg/g) are higher than that of earth crust and mudstone, the indexes of the anoxic reducing environment in the Longmaxi stage in the study area. The relative sea level of the Lower Silurian Longmaxi period, which correlates to total organic carbon content, experienced two rise-and-fall cycles; meanwhile, the reducibility of the ancient sea waters experienced a similar period of rise-and-fall cycles. Total organic carbon content is quite higher near the maximum flooding surface in study area. After mineral analysis, the reservoir property was found to be similar to the Ohio shale that provided the first commercial gas production in the United States, thereby inspiring and instructing shale gas exploration and exploitation southeast of Chongqing.

The Potential of China's Lacustrine Shale Gas Resources:

China is rapidly advancing both theoretical research and practical exploration of her shale gas deposits. Shale gas deposits in China span the gamut of the basic geological features e.g.: marine facies, marine-continental transitional facies, continental facies, and many strata covering the Palaeozoic, Mesozoic, and Cenozoic. Lacustrine shale contained abundant organic matter is mainly developed in the Mesozoic-Cenozoic and is distributed across the North of China, with local occurrences in southern regions. The deposits are characterised by thin monolayer thickness, many inter-beds, large total thickness, rapid lateral variation, varied organic matter types, and a low degree of thermal evolution. The favourable conditions for forming the shale gas enrichment of Chinas lacustrine organic rich shale mainly include: abundant reservoir porosity, varied organic matter types, large total thickness, good preservation conditions, resource abundance, and favourable surface conditions; the unfavourable conditions mainly include: poor areal continuity, sudden changes in cross-section, and relatively low maturity. At present, continental shale gas exploration of Triassic deposits in the Ordos basin and Jurassic deposits in the Sichuan basin have made significant breakthroughs. Based on the present state of Chinas shale gas exploration and development, combined with investigation and evaluation, the work demands favourable zone optimisation for Chinas shale gas resource potential to be best exploited. Shale gas enrichment is considered, not only through determination of the resources physical boundary with many types and complex geological conditions pertaining to shale gas in China, but in combination with the paucity of shale gas exploration-related geological data and paucity of geological knowledge: the relevant computation parameters are difficult to ascertain accurately, thus the probability volume method is used to evaluate potential continental shale gas strata, including Triassic, Jurassic, Cretaceous and Palaeogene deposits in northern, and north-eastern China, Triassic, Jurassic, Cretaceous, and Palaeogene deposits in northwest regions, some Permian deposits, Jurassic deposits from the upper Yangtze and Dian Qian-Gui(Yunnan-Guizhou-Guangxi) regions, and Jurassic and Palaeogene deposits from the middle-lower Yangtze and southeast region. Estimated continental shale gas resources recoverable in China are 7.92×1012 m3, which accounts for 31.59% of her total shale gas recoverable resources. Among them, continental exploitable resource potential is greatest in northern, and northeast regions of China (c. 3×1012 m3, some 37.75% of the total shale gas resource recoverable), followed by the northwest region, the upper Yangtze and Dian-Qian-Gui regions, the middle-lower Yangtze, and the southeast region. Geological resources, and recoverable resources, of Jurassic continental shale gas are the largest (c. 3.77×1012 m3, some 47.6% of the total continental shale gas resource recoverable), followed by Cretaceous, Palaeogene, Triassic, and Permian deposits.

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][1] ), 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. [1]: /embed/mml-math-1.gif

Lacustrine Shale Deposition and Variable Tectonic Accommodation in the Rift Basins of the Bohai Bay Basin in Eastern China

Organic-rich lacustrine shales are widely distributed in China and have significant potential for unconventional shale gas and oil production although the primary factors controlling the deposition of lacustrine shale are disputed. This work clarifies the different characteristics of tectonic evolution and shale among sub-basins in the Bohai Bay Basin in eastern China as a case study by studying basal subsidence, tectonic subsidence rate, basin extensional proportions and shale chemical characteristics. The paper summarizes the correlation between structure and shale deposition, and concludes that tectonic activity is the primary controlling factor for shale development. Episodic tectonic activity controls not only the timing of shale deposition (with the greatest shale deposition occurring primarily during the peak period of basin tectonic activity) but also the spatial distribution of shale (located mainly in areas of maximum subsidence), the migration pattern of shale (conforming to that of the basin subsidence center), and shale strata thickness. Tectonic activity also affects the total organic carbon content and organic matter type in shale. When the tectonic activity was the most active and basal subsidence was the maximum, the total organic carbon content of the shale reached its highest value with organic matter type mainly Type I. As tectonic activity weakened, the total organic carbon content decreased, and the organic matter type changed from Type I to Type I-III.

Geology and shale gas resource potentials in the Sichuan Basin, China

The organic-rich shales in the Sichuan Basin in China include Pre-Cambrian Sinian to Middle Permian marine shales deposited in passive margin to foreland settings, Upper Permian transitional shales deposited in a coastal swamp setting, and Triassic and Jurassic lacustrine shales deposited in a foreland setting. Regional shale property mapping, analysis of geochemistry, mineralogy and petrophysics based on sample tests, reservoir characterization of potential shale intervals, and recent exploration and production (E&P) results reveal that: Pre-Cambrian to Middle Permian marine shales, especially the Lower Silurian Longmaxi shale, deposited during transgressive systems tract to early highstand systems tract period have significant reservoir storage, high TOC, high maturity, high brittle mineral content and high gas content, and are similar to the Barnett shale in USA to hold a huge amount of shale gas. The coal-associated Upper Permian transitional shales and Triassic to Jurassic lacustrine shales are relatively clay-rich compared to marine shales, but possess some shale gas potential in organic-rich shales. The shale gas resource potentials and emerging production have been confirmed by the reservoir characteristics and test results of recent drilled wells targeting marine, transitional and lacustrine shale gas in the Sichuan Basin.

Geological and Geochemical Evidence on the Identification of Natural Gas Migration Through Fault System, Baiyun Sag, Pearl River Mouth Basin, China

The origin of natural gas has been analyzed based on the regional geological characteristics of Baiyun Sag and carbon isotopic composition of methane and ethane. The results show that the natural gas is mainly derived from the type II-III organic matter. The analysis of fault activity near slope shows that the four zones can be classified based on the fault activity intent with geological time. The fault activity intent decreases from Zone I to IV. In addition, the fault activity varies between east and west, north and south. The fourth line fault activity is more intense than the third line fault. In turn, the third line fault activity is more intense than the second line fault. The fault active period control the gas migration, and close period can be as seal for gas trap. The geochemical characteristics of the adsorbed gas in sample log verified that fault do play an important role for gas migration. The fault activity coincided with the isotopic composition of the adsorbed gas. For example, the shallow strata in Well PY34-1-1 are biogenic gas, and thermal gas is mainly in the deep part of T5 strata with indistinct fault activity in this region. In contrast, the shallow strata in Well LH19-1-1 are mainly thermal gas because of intense fault activity. The carbon isotopic composition of methane of adsorbed gas is ca. −30‰, and this shows the thermal gas migration in the shallow strata through fault. In the meantime, the homogenization temperature of fluid inclusion in different wells also coincided with the adsorbed gas characteristics and fault activity. As the fault activity is intense, the more peaks of homogenization temperature were recorded as the fluid activity appeared. These evidences prove that the fault mainly controls the migration and distribution of gas vertically.

Study on the Effect of Source-Contacting Gas Accumulations upon Abnormal Pressures in Western Sichuan Depression

Abstract The migration and accumulation of typical source-contacting gas, also called basin-centered gas, follow the piston principle that it generates superpressures essentially. In the tight sand reservoir, the formation water cannot exchange sufficiently, which maintains higher pressure in gas reservoirs compared with conventional reservoirs during tectonic uplift or subsidences. The western Sichuan depression is one of the earliest basins in China being researched for source-contacting gas, where the regional overpressure is the direct product and the sign of the accumulation of source-contacting gas. Besides the effect from the accumulation of source-contacting gas, the regional overpressure in the western Sichuan depression is also directly related with undercompaction and regional tectonic uplift before and after the accumulation of source-contacting gas, respectively. Present regional overpressure in the western Sichuan depression is attributed to three phases of tectonic movements and generations of abnormal pressure thrice due to the preferable obturation of the unconventional gas accumulation systems. The multiple pressures were believed to cumulate from undercompaction and hydrocarbon generation before the Late Jurassic period, from gas generation and accumulation of source-contacting gas in the Late Jurassic to Eogene period, and cumulation of multiple pressures after the Late Eogene is attributed to regional uplift. Using section configuration and calculation, the coefficients of abnormal pressures in the western Sichuan depression can be divided as follow: the coefficients of abnormal pressure due to undercompaction and regional uplift is 1.42 and the rest over-pressures is attributed to the accumulation of source-contacting gas. According to the isolines 1.42 of pressure coefficients, the distribution of source-contacting gas accumulations can be approximately predicted.

Geological Controls and Mechanism of Shale Gas and Shale Oil Accumulations in Liaohe Western Depression, China:

Recently, the accumulation of shale gas and shale oil in the rifted lacustrine basin of China has garnered increasing interest. In this paper, the shale located in the Shahejie Formation of the Liaohe western depression of the Bohai Bay Basin was selected as the focus of a comprehensive evaluation of the geological controls of shale gas and shale oil accumulation. (1) In a rifted lacustrine basin, the subsidence rate of the stratigraphy is rapid, which results in a massive sedimentation of organic-rich shale. The shale that developed in the deep and semi-deep lacustrine facies is characterized by a high concentration of organic matter, with an average total organic carbon (TOC) content over 2.0% being measured. The TOC consists primarily of type I-II1 kerogen, which contains abundant sapropelic materials and has relatively low thermal maturity, ranging from 0.4 to 0.9%Ro, due to the shallow burial depth and the young deposition epoch. (2) Various pore-fractures in the core samples and erosion occurring in the calcareous and dolomitic shales were observed, which provide storage space for oil-gas accumulations. Furthermore, the mechanisms of the accumulation of shale gas and shale oil in the study area were established according to analyses of the geochemistry characteristics and the sedimentary environment, as well as a thermal pressure simulation experiment. Overall, the accumulation model of shale oil-gas is characterized by “upper oil and lower gas”. In addition, oil-gas resources in siltstone, dolomite and limestone, which are adjacent to or interbedded with organic-rich shale, are also important targets in shale reservoirs.

Dynamic equations for nonassociated gas accumulation

Abstract Nonassociated gas can be classified as conventional gas accumulation with displacement migration, source-contacting gas accumulation with piston-type migration, and shale gas accumulation with the displacement and piston-type migrations. Nonassociated gas accumulation can be described by using the continuous but universal dynamic equation. The accumulation of conventional trap gas is controlled by buoyancy and capillary pressure, and the accumulation dynamic equilibrium is influenced by the height of the continuous gas column and the physical properties of seal rocks. Source-contacting gas accumulation is associated with gas-generating intensity of source rocks, physical properties of reservoirs, and accumulation depth, and the accumulation dynamic equilibrium is constrained mainly by the effectiveness of gas generation and the physical properties of tight sand reservoirs. In complicated geologic settings of shale gas accumulation, effectiveness of gas generation, physical properties of reservoirs, height of continuous gas column, and buried depth are the conditions influencing the accumulation of nonassociated gas.