Coal-measure Source Rocks Research Articles

Genetic Types and Source of the Upper Paleozoic Tight Gas in the Hangjinqi Area, Northern Ordos Basin, China

The molecular and stable isotopic compositions of the Upper Paleozoic tight gas in the Hangjinqi area in northern Ordos Basin were investigated to study the geochemical characteristics. The tight gas is mainly wet with the dryness coefficient (C1/C1–5) of 0.853–0.951, andδ13C1andδ2H-C1values are ranging from-36.2‰to-32.0‰and from-199‰to-174‰, respectively, with generally positive carbon and hydrogen isotopic series. Identification of gas origin indicates that tight gas is mainly coal-type gas, and it has been affected by mixing of oil-type gas in the wells from the Shilijiahan and Gongkahan zones adjacent to the Wulanjilinmiao and Borjianghaizi faults. Gas-source correlation indicates that coal-type gas in the Shiguhao zone displays distal-source accumulation. It was mainly derived from the coal-measure source rocks in the Upper Carboniferous Taiyuan Formation (C3t) and Lower Permian Shanxi Formation (P1s), probably with a minor contribution from P1s coal measures from in situ Shiguhao zone. Natural gas in the Shilijiahan and Gongkahan zones mainly displays near-source accumulation. The coal-type gas component was derived from in situ C3t-P1s source rocks, whereas the oil-type gas component might be derived from the carbonate rocks in the Lower Ordovician Majiagou Formation (O1m).

Geochemical characteristics and origin of natural gas in the Dongping–Niudong areas, Qaidam Basin, China

The geochemical characteristics, origin, and source of natural gas in the Dongping–Niudong areas are researched based on the information of components and the stable carbon isotopes of natural gas. The main component of hydrocarbon gas is methane, and C2+ possesses a relatively low content that ranges from 0.5% to 6.5%. The dryness coefficient of the Dongping area is more than 0.97, which categorizes as dry gas. The dryness coefficient of the Niudong area ranges from 90.3% to 98.1%, whilst having the characteristics of dry gas coexisting with wet gas. The δ13C1 dryness coefficient varies from −17.58‰ to −36.4‰, and δ13C2 is greater than −29‰. The gas of the Dongping 3 block has the characteristics of an abiogenic gas such as the reversed carbon isotope series. The combination of the relationship between the component of CO2 and δCCO213 and the background of development of hydrocarbon-generating sag, suggests that it is coal-derived gas. The RO and fluid inclusion studies show that the gas in Niudong area is mainly derived from Early Jurassic coal-measure source rocks of Kunteyi Sag, and there are two periods of hydrocarbon fillings. The first filling is mainly oil, and the second is mainly high mature gas; gas in Dongping area is mainly derived from Early Jurassic coal-measure source rocks of Pingdong–Yiliping Sag, and there are four periods of high-over mature gas fillings. The phenomenon of reversed carbon isotope series in Dongping area resulted from the multiple gas charging.

The experimental modeling of gas percolation mechanisms in a coal-measure tight sandstone reservoir: A case study on the coal-measure tight sandstone gas in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

Tight sandstone gas from coal-measure source rock is widespread in China, and it is represented by the Xujiahe Formation of the Sichuan Basin and the Upper Paleozoic of the Ordos Basin. It is affected by planar evaporative hydrocarbon expulsion of coal-measure source rock and the gentle structural background; hydrodynamics and buoyancy play a limited role in the gas migration-accumulation in tight sandstone. Under the conditions of low permeability and speed, non-Darcy flow is quite apparent, it gives rise to gas-water mixed gas zone. In the gas displacing water experiment, the shape of percolation flow curve is mainly influenced by core permeability. The lower the permeability, the higher the starting pressure gradient as well as the more evident the non-Darcy phenomenon will be. In the gas displacing water experiment of tight sandstone, the maximum gas saturation of the core is generally less than 50% (ranging from 30% to 40% and averaging at 38%); it is similar to the actual gas saturation of the gas zone in the subsurface core. The gas saturation and permeability of the core have a logarithm correlation with a correlation coefficient of 0.8915. In the single-phase flow of tight sandstone gas, low-velocity non-Darcy percolation is apparent; the initial flow velocity (Vd) exists due to the slippage effect of gas flow. The shape of percolation flow curve of a single-phase gas is primarily controlled by core permeability and confining pressure; the lower the permeability or the higher the confining pressure, the higher the starting pressure (0.02–0.08 MPa/cm), whereas, the higher the quasi-initial flow speed, the longer the nonlinear section and the more obvious the non-Darcy flow will be. The tight sandstone gas seepage mechanism study shows that the lower the reservoir permeability, the higher the starting pressure and the slower the flow velocity will be, this results in the low efficiency of natural gas migration and accumulation as well as low gas saturation. The laboratory modeling on gas migration accumulation mechanism in coal-measure tight sandstone can provide a theoretic foundation to reveal the tight sandstone gas enrichment regularity, evaluation of prospecting area, and the study of development mechanism.

Geochemical characteristics of tight gas and gas-source correlation in the Daniudi gas field, the Ordos Basin, China

The molecular composition, stable carbon and hydrogen isotopes and light hydrocarbons of the Upper Paleozoic tight gas in the Daniudi gas field in the Ordos Basin were investigated to study the geochemical characteristics. Tight gas in the Daniudi gas field displays a dryness coefficient (C1/C1–5) of 0.845–0.977 with generally positive carbon and hydrogen isotopic series, and the C7 and C5–7 light hydrocarbons of tight gas are dominated by methylcyclohexane and iso-alkanes, respectively. The identification of gas origin and gas-source correlation indicate that tight gas is coal-type gas, and the gases reservoired in the Lower Permian Shanxi Fm. (P1s) and Lower Shihezi Fm. (P1x) had a good affinity and were derived from the P1s coal-measure source rocks, whereas the gas reservoired in the Upper Carboniferous Taiyuan Fm. (C3t) was derived from the C3t coal-measure source rocks. The molecular and methane carbon isotopic fractionations of natural gas support that the P1x gas was derived from the P1s source rocks. The differences of geochemical characteristics of the C3t gas from different areas in the field suggest the effect of maturity difference of the source rocks rather than the diffusive migration, and the large-scale lateral migration of the C3t gas seems unlikely. Comparative study indicates that the differences of the geochemical characteristics of the P1s gases from the Yulin and Daniudi gas fields originated likely from the maturity difference of the in-situ source rocks, rather than the effect of large-scale lateral migration of the P1s gases.

The origin of gas in the Changxing–Feixianguan gas pools in the Longgang gas field in the Sichuan Basin, China

In this paper, the origin of natural gas in the formations of the Changxing–Feixianguan within the Longgang gas field was studied in detail using geochemical methods. The gas discovered has a very high dryness coefficient, yet low ethane and other less heavy hydrocarbons content. Apart from a small amount of N2 and CO2 gasses it generally contains H2S. In the field location, the Changxing–Feixianguan formations itself does not have a hydrocarbon generation potential. Nearing the edge of the Kaijiang-Liangping Trough, there developed the Dalong Formation. However, it also has a very low TOC content in the area of the Longgang gas field, and it cannot act as an effective source rock. The geochemistry of natural gas is much different from the gasses generated by the Silurian and Cambrian source rocks. Therefore, it is impossible that the gas in the Longgang gas field is from the Silurian and Cambrian source rocks. Gas reservoirs generally contain bitumen which is considered a product of crude oil cracking. The carbon isotope fractionation between the bitumen and methane is not distinct, and it indicates that the gas is not directly from oil cracking. The carbon of methane and ethane has isotopically less negative value, which is considered to be in a high-overmature coal-formed gas, mainly from the Longtan Formation coal measures. In comparison to the gas from high overmature stage obtained from the Xujiahe coal measure source rock in the Western Sichuan Depression. The methane in the Longgang gas field has abnormal less negative carbon isotopic value. It is due to the superposition of these two factors together: higher evolution of source rocks and mixing of gas degassing from the water. It is not caused by TSR that most researchers believed at present because the methane carbon isotopic values have no relationship with H2S content.

Source of condensate oil in the middle of southern margin, Junggar Basin, NW China

Abstract Through detailed geochemical analysis of over 40 crude oil, condensate oil and heavy oil samples in the southern margin of Junggar Basin, and based on the hydrocarbon generation condition of five sets of source rocks, with the combination between compositions of carbon isotopes of whole oil, light hydrocarbon, n-alkanes isoprenoids and biomarker composition characteristics, a detailed discussion on the source of the condensate oil in anticlines in the central part of the southern margin was carried out. Condensate oils from the central part of the southern margin have abundant isoprenoids, Pr/Ph 13 C value between −27‰ and −28‰. The δ 13 C value of alkanes with carbon number smaller than 9 ranges from −26‰ to −24‰, carbon isotopes of C 9+ n-alkanes decrease remarkably with increasing carbon number, and the δ 13 C value of C 19+ n-alkanes is lower than −30‰. The δ 13 C value of pristane and phytane is lower than −29‰. The biomarker components contain abundant C 27 steranes and C 30 methyl steranes, “V” shape distribution of C 27 , C 28 and C 29 20R sterane, abundant tricyclic terpanes with dominance of C 21 , and relatively high content of gammacerane with two isomers. The 20 S /(20 S +20 R ) ratio of C 29 steranes is between 0.40 and 0.50, and the maturity calculated by the methylphenanthrene index and distribution fraction ( R c ) ranges from 0.70% to 1.1%. These geochemical characteristics of the condensate oils are very similar to those mature crude oils from the typical Cretaceous lacustrine source rocks in the central part of southern margin, but are greatly different from those of typical Jurassic crude oils, implying that these condensate oils are derived from mature Cretaceous lacustrine source rocks instead of highly mature Jurassic coal-measures source rocks.

River-delta systems: a significant deposition location of global coal-measure source rocks

Natural gas is providing a larger proportion of primary energy, and will soon surpass oil to become the most important fossil fuel. There are various genetic types of natural gas of which the type that pyrolysed or cracked from humic kerogen accounts for 70% of presently discovered global natural gas reserves. The parent material of humic kerogen is higher multi-cellular plants. Investigations of offshore basins in China, Russia, Indonesia, Bangladesh, Australia, Egypt and Namibia show that river-delta systems contain the major sources of coal-type gas. Sand and mud carried by rivers form deltas at river mouths and fertile soil of these deltas encourages the long-term growth of higher plants. Autochthonous higher plants and allochthonous terrigenous phytoclasts contribute to the formation of coal, carbargilite and dark mudstone, which are potential parent materials of natural gas and the basis of coal-type gas generation.

Coal-measure source rock characteristics and burial evolution history in the Shisanjianfang Area, Tuha Basin

Shisanjianfang Area in the eastern margin of Taibei Sag, Tuha Basin, is an important region for oil and gas exploration. In this study, a large number of source rock geochemical data were used to analyze the geochemical characteristics of coal-measure source rocks in the Shisanjianfang Area, Tuha Basin, from three aspects, i.e., organic matter abundance, organic matter type, and organic maturity. The results show that the Jurassic Xishanyao Formation (J2x) in the study area has great thickness, continuous distribution, and high source rock maturity, and is the major source rock horizon in the study area. The seismic data are used in combination with 1D and 2D basin simulation technology to study the distribution characteristics of the source rocks in Shisanjianfang Area. The results of the simulation research on the source rock maturity history in the study area indicate the following: (1) The source rocks in the Xishanyao Formation (J2x) have a hydrocarbon generation threshold depth of 1800 m, threshold temperature of 95 °C, and hydrocarbon generation threshold time of about 162 Ma. (2) The Xishanyao Formation (J2x) has a current formation temperature of 50~110 °C and Ro of 0.6~1.1 % in the peak oil generation stage. (3) The source rock maturity in the study area is shown as being higher in the west while lower in the east, and higher in the north while lower in the south, and the favorable exploration area mainly lies in the northwest of the study area. The results of this study could have important implications for the oil and gas exploration in the margins of Xiaocaohu Sag, Tuha Basin.

Geology and hydrocarbon accumulations in the deepwater of the northwestern South China Sea—with focus on natural gas

The deepwater of the northwestern South China Sea is located in the central to southern parts of the Qiongdongnan Basin (QDN Basin), which is a key site for hydrocarbon exploration in recent years. In this study, the authors did a comprehensive analysis of gravity-magnetic data, extensive 3D seismic survey, cores and cuttings, paleontology and geochemical indexes, proposed the mechanism of natural gas origin, identified different oil and gas systems, and established the model of hydrocarbon accumulations in the deep-water region. Our basin tectonic simulation indicates that the evolution of QDN Basin was controlled by multiple-phased tectonic movements, such as Indochina-Eurasian Plate collision, Tibetan Uplift, Red River faulting and the expansion of the South China Sea which is characterized by Paleogene rifting, Neogene depression, and Eocene intensive faulting and lacustrine deposits. The drilling results show that this region is dominated by marineterrestrial transitional and neritic-bathyal facies from the early Oligocene. The Yacheng Formation of the early Oligocene is rich in organic matter and a main gas-source rock. According to the geological-geochemical data from the latest drilling wells, Lingshui, Baodao, Changchang Sags have good hydrocarbon-generating potentials, where two plays from the Paleogene and Neogene reservoirs were developed. Those reservoirs occur in central canyon structural-lithologic trap zone, Changchang marginal trap zone and southern fault terrace of Baodao Sag. Among them, the central canyon trap zone has a great potential for exploration because the various reservoirforming elements are well developed, i.e., good coal-measure source rocks, sufficient reservoirs from the Neogene turbidity sandstone and submarine fan, faults connecting source rock and reservoirs, effective vertical migration, late stage aggregation and favorable structural–lithological composite trapping. These study results provide an important scientific basis for hydrocarbon exploration in this region, evidenced by the recent discovery of the significant commercial LS-A gas field in the central canyon of the Lingshui Sag.

Contribution of moderate overall coal-bearing basin uplift to tight sand gas accumulation: case study of the Xujiahe Formation in the Sichuan Basin and the Upper Paleozoic in the Ordos Basin, China

Tight sand gas is an important unconventional gas resource occurring widely in different petroleum basins. In coal-bearing formations of the Upper Triassic in the Sichuan Basin and the Carboniferous and Permian in the Ordos Basin, coal measure strata and tight sandstone constitute widely distributed source–reservoir assemblages and form the basic conditions for the formation of large tight sand gas fields. Similar to most tight gas basins in North America, the Sichuan, and Ordos Basins, all experienced overall moderate uplift and denudation in Meso-Cenozoic after earlier deep burial. Coal seam adsorption principles and actual coal sample simulation experiment results show that in the course of strata uplift, pressure drops and desorption occurs in coal measure strata, resulting in the discharge of substantial free gas. This accounts for 28 %–42 % of total gas expulsion from source rocks. At the same time, the free gases formerly stored in the pores of coal measure source rocks were also discharged at a large scale due to volumetric expansion resulting from strata uplift and pressure drop. Based on experimental data, the gas totally discharged in the uplift period of Upper Paleozoic in the Ordos Basin, and Upper Triassic Xujiahe Formation in the Sichuan Basin is calculated as (3–6) × 108 m3/km2. Geological evidence for gas accumulation in the uplift period is found in the gas reservoir analysis of the above two basins. Firstly, natural gas discharged in the uplift period has a lighter carbon isotope ratio and lower maturity than that formed in the burial period, belonging to that generated at the early stage of source rock maturity, and is absorbed and stored in coal measure strata. Secondly, physical simulation experiment results at high-temperature and high-salinity inclusions, and almost actual geologic conditions confirm that substantial gas charging and accumulation occurred in the uplift period of the coal measure strata of the two basins. Diffusive flow is the main mode for gas accumulation in the uplift period, which probably reached 56 × 1012 m3 in the uplift period of the Xujiahe Formation of the Sichuan Basin, compensating for the diffusive loss of gas in the gas reservoirs, and has an important contribution to the formation of large gas fields. The above insight has promoted the gas resource extent and potential of the coal measure tight sand uplift area; therefore, we need to reassess the areas formerly believed unfavorable where the uplift scale is large, so as to get better resource potential and exploration prospects.

Controlling effect of three major faults on gas accumulation in the Xujiaweizi faulted depression, Songliao Basin

Understanding the major controlling factors of gas accumulation in the Xujiaweizi faulted depression of the Songliao Basin is of great significance to future gas exploration. However, they were seldom studied in the context of major faults including Xuxi, Xuzhong and Xudong. Based on fine interpretation of 3D seismic data acquired in this area, the controlling effect of these three faults on gas accumulation and distribution was identified through a composite analysis of the three faults and the gas accumulation conditions considering the characteristics of development and distribution of the three major faults. The following conclusions were obtained. (1) These faults jointly control the development of coal measure source rocks in the Lower Cretaceous Shahezi Fm. Such rocks show three high-value areas of thickness (with the maximum thickness of over 1000 m) and have a large potential of hydrocarbon generation. These faults provide passages for gas to migrate upwards to the overlying reservoirs. (2) These faults act as the pathways for magma to protrude upwards into the shallow crust during the deposition of Early Cretaceous Yingcheng Fm. Volcanic rocks are well-developed around the faults, forming favorable fractured volcanic reservoirs. (3) These faults provide effective sealing conditions for gas accumulation in the volcanic reservoirs. If the fault cutting Ying 1 Member is juxtaposed by volcanic reservoirs and sandstones or conglomerates at both walls, the fault is sealed laterally, which is favorable for gas accumulation, and gas layer is proved through drilling; otherwise, if juxtaposed by volcanic rocks, the fault is not sealed laterally, which is unfavorable for gas accumulation, and water layer is confirmed through drilling.

Geochemical characteristics of Lower Permian coal-measure source rocks in Northeast Ordos Basin

General characteristics and biomarker distributions of Lower Permian coal-measure source rocks in northeastern Ordos Bsain have been analyzed in this paper. The results show that the source rocks are type Ⅲ kero- gen, thermally mature, with high content of total organic carbon. The extracts of the source rock samples with dif- ferent lithologies from Well Su 27 feature high Pr/Ph ratios, high C19TT and C24Te, high rearranged hopanes, a pre- dominance of C29 sterane in regular steranes, and the absence of C30 4-methylsteranes. These data suggest that the source rocks were deposited in suboxic to oxic conditions with dominantly terrigenous higher plant input. In con- trast, the source rocks from wells Shuang 1 and Yu 20, are characterized by low Pr/Ph ratios, low C19TT and C24Te, high C23TT, similar content of C27 sterane and C29 sterane, and the presence of C30 4-methylsteranes, showing that the source rocks were deposited in reducing environment with algae and/or microorganisms and terrigenous higher plant input.

Reservoir-forming by lateral supply of hydrocarbon: A new understanding of the formation of Ordovician gas reservoirs under gypsolyte in the Ordos Basin

There developed thick gypsum-salt strata in the Lower Paleozoic Ordovician in the Ordos Basin, particularly gypsum-salt in the 6th segment of the 5th member of Majiagou Fm (O1m56) in a wide distribution, serving as a good regional cap. Recent drilling and relevant studies have proven that the hydrocarbon-generating capacity of the marine-facies hydrocarbon source rocks under the Ordovician salt layers in the eastern Basin is poor on the whole, making it difficult to form ”self-generating and self-preserving type” commercial gas reservoirs under the salt layer in Mizhi salt subsag. However, further research on reservoir-forming conditions under the gypsolyte on the west side of the salt subsag indicates that the O1m57 – O1m510 strata near the east side of the palaeo-uplift contact directly with the Upper Paleozoic coal measure source rocks, forming a “hydrocarbon supply window”; the Yanshan Movement caused the tectonic inversion of the basin main body, resulting in the tectonic framework “high in the east and low in the west”, which is conductive to the further migration of natural gas generated by the Upper Paleozoic coal measures to the updip high position of the east side along the O1m57 – O1m510 carrier beds after entering the dolomite reservoir under the gypsolyte through the “hydrocarbon–supply window”. In addition, the facies changes in the dolomite rocks under the gypsum-salt provide favorable barrier condition for the regional gathering of natural gas. Therefore, it is concluded through comprehensive analysis that reservoirs may form beneath the Ordovician gypsolith in the central region of the basin on the west side of the salt subsag with hydrocarbon supplied from the Upper Paleozoic source rocks of coal measures, which is expected to open up a new situation of natural gas exploration under the Ordovician gypsum-salt layer in the Ordos Basin.

An analysis of natural gas exploration potential in the Qiongdongnan Basin by use of the theory of “joint control of source rocks and geothermal heat”

The Oligocene Yacheng Fm contains the most important source rocks that have been confirmed by exploratory wells in the Qiongdongnan Basin. The efficiency of these source rocks is the key to the breakthrough in natural gas exploration in the study area. This paper analyzes the hydrocarbon potential of each sag in this basin from the perspective of control of both source rocks and geothermal heat. Two types of source rocks occur in the Yacheng Fm, namely mudstone of transitional facies and mudstone of neritic facies. Both of them are dominated by a kerogen of type-III, followed by type-II. Their organic matter abundances are controlled by the amount of continental clastic input. The mudstone of transitional facies is commonly higher in organic matter abundance, while that of neritic facies is lower. The coal-measure source rocks of transitional facies were mainly formed in such environments as delta plains, coastal plains and barrier tidal flat-marshes. Due to the control of Cenozoic lithosphere extension and influence of neotectonism, the geothermal gradient, terrestrial heat flow value (HFV) and level of thermal evolution are generally high in deep water. The hot setting not only determines the predominance of gas generation in the deep-water sags, but can promote the shallow-buried source rocks in shallow water into oil window to generate oil. In addition to promoting the hydrocarbon generation of source rocks, the high geothermal and high heat flow value can also speed up the cracking of residual hydrocarbons, thus enhancing hydrocarbon generation efficiency and capacity. According to the theory of joint control of source quality and geothermal heat on hydrocarbon generation, we comprehensively evaluate and rank the exploration potentials of major sags in the Qiongdongnan Basin. These sags are divided into 3 types, of which type-I sags including Yanan, Lingshui, Baodao, Ledong and Huaguang are the highest in hydrocarbon exploration potential.

Novel tetracyclic terpanes in crude oils and source rock extracts in pearl river mouth basin and their geological significance

Novel tetracyclic terpanes X and Y namely C24-des-A-oleanane and C27 tetracyclic terpane were detected in crude oils and source rock extracts in Zhu 1 depression in Pearl River Mouth Basin by GC-MS analysis technology. These compounds are similar to oleanane in the structure, and their relative abundance in m/z 191 partial mass chromatogram has a good correlation with oleanane. Here compounds X and Y are considered to be derived from the des-A degradation of oleanoid precursor. The ratio of X/(X+C24) and Y/(Y+C24) increase with the increasing inputs of terrigenous organic matter in crude oils. Wenchang Formation middle-deep lacustrine source rocks with planktonic algae organic matter inputs and oil generating from it contain low abundance of compounds X and Y, while Enping Formation coal measures source rocks with terrigenous higher plants organic matter inputs and oil generating from it usually have higher compounds X and Y. In general when two terrigenous compounds C19 tricyclic terpane and bicadinane-T are high in crude oils, there are also a corresponding high abundant compounds X and Y. Relative abundance of compounds X and Y is closely related to the source of organic matter and it can indicate the input of terrigenous organic matter.

Formation and Distribution of Tight Sand Gas Reservoirs in the Sichuan Basin, China

Located in the central west of China, the Sichuan Basin is abundant in natural gas resources. It is the earliest basin where natural gas was discovered and utilized in the world. After more than 60 years’ exploration, many gas fields have been found in the Paleozoic - Mesozoic carbonate and clastic formations. The basin has become a critical production base in China for its cumulative proved recoverable gas reserves of more than 8000×10 8 m 3 , and gas production over 150×10 8 m 3 in 2010. During the past decade, many tight gas reservoirs have been found in the Xujiahe coal measures of the upper Triassic continental deposits. Based on lithology, this suite of formation can be divided into six members from bottom to top. The source rocks are the coal beds and carbon-bearing mudstones in Xu1, Xu3 and Xu5 members with relatively high organic carbon contents and type III kerogen; the reservoir rocks are the tight sandstones in Xu2, Xu4 and Xu6 members. The source rocks and the reservoirs distribute alternatively and widely in “sandwiched” structure, providing favorable conditions for natural gas accumulating near source. As the formations are gentle and lack of structural traps, the lithologic gas reservoirs dominate the Xujiahe tight sandstones. Both coal-measure source rocks and sandstone reservoir distribute in strong heterogeneity, leading to thin gas-layers in the reservoir, poor continuity in plane, and varying full-up ratio and gas saturation in the gas reservoir. Within the 80,000 km 2 area, the Xujiahe Formation has the features of widespread gas-bearing beds and local gas enrichment. The current high-yield gas wells are mainly distributed in the tectonic highs or fractured zones in the areas with effective source-reservoir assemblages. The resources assessment is made considering the tight gas accumulating intensively into reservoir. It reveals the favorable gas-bearing area up to 6-7×10 4 km 2 and the estimated recoverable gas reserves of 2-3×10 12 m 3 in the Xujiahe Formation. Key words: Sichuan Basin; Tight sandstone; Coal measures; Tight gas; “Sandwiched” structure; Resources

Preliminary Source Rock Evaluation of Lower-Cretaceous Coal-Measures Strata in Hulin Basin in Northeastern China

According to the thermal decomposition achievement of coal shale and coal samples, which are gathered from the Lower-Cretaceous coal-measure strata of Hulin basin, the organic matter abundance, type and maturation have been analyzed with TOC, S1+ S2, Hydrogen Index, content of maceral, Tmax , Ro. The result indicates that the organic abundance of coal shale and coal in Qihulin formation is average ,kerogen type is type III and their thermal evolution is over mature . The organic abundance of coal shale in Yunshan formation is general to better while the coal’s organic abundance is from better to best, they are both type III kerogen, and their thermal evolution is mature. The above analysis indicates that the hydrocarbon generating potential is limited in the Lower-Cretaceous coal-measure strata of Hulin basin while coal-measure source rocks in the Yunshan formation have good hydrocarbon generating potential.

Geochemical characteristics and source of natural gases from Southwest Depression of the Tarim Basin, NW China

The molecular compositions and stable carbon and hydrogen isotopes of natural gases from the Kekeya, Kedong and Akemomu gas fields in the Southwestern Depression of the Tarim Basin were investigated to distinguish between coal-derived and oil-associated gases. The carbon and hydrogen isotope ratios indicate that the gaseous alkanes from these three fields were mainly coal-derived and sourced from the Middle–Lower Jurassic humic source rocks. The gaseous alkanes in natural gas from the Kekeya and Kedong fields were generated from low maturity humic source rocks. However, the light hydrocarbons display the characteristics of marine sapropelic gas, and the high δD1 values and partial carbon isotopic reversal of alkanes indicated that the gases had been mixed with oil-associated gas derived from the Carboniferous–Permian sapropelic source rocks. The alkanes in natural gas from the Akemomu Field display high carbon isotopic ratios and were probably derived from the Middle–Lower Jurassic humic source rocks in high to overmature stage. The high contents of CO2 with high δ13CCO2 values were mainly derived from the thermal decomposition of Carboniferous limestones. The high content of N2 was likely derived from highly overmature coal measure source rocks.

Organic Matter Characteristics of Coal Measure Source Rocks of Well Wanggu 1 in Huanghua Depression

Applying the method of source rocks pyrolysis to analyze 19 pieces of coal measure source rocks of Shanxi-Taiyuan group in Huanghua Depression, the results show that the level of organic matter abundance of coal measures hydrocarbon source rock in Shanxi-Taiyuan group of Well Wanggu 1 is the poor. Using monadic linear regression method to analysis the data of S2 and TOC, the results show that the type of the mudstone organic matter in the Shanxi - Taiyuan group belongs to III, the type of coal sample organic matter in Shanxi-Taiyuan group belongs to I. Due to the data of samples in the Shanxi group is less, the results of the coal sample in Shanxi group are only for reference. According to the data of Tmax, the most of the coal measures hydrocarbon source rocks in Shanxi - Taiyuan group are in the maturity stage, several samples are in the high maturity stage.

The Study on Hydrous Pyrolysis Experiments of Coal-Measure Source Rocks in Ordos Basin

Through the hydrous pyrolysis experiments of coal-measure source rocks in Taiyuan formation in Ordos Basin with different mediums from 250 °C to 550 °C, with a stepwise heating stage of 50 °C, the characteristics of gas and liquid products are discussed systematically in this paper. The results show that the change rule of hydrocarbon productivity of coal with temperature is similar to mudstone. Total hydrocarbon productivity and gas hydrocarbon productivity increase with temperature rise. Liquid hydrocarbon productivity increases with temperature rise first and then decreases. The peak yield of oil of coal appears at the heating temperature 350 °C, mudstone at 375 °C. The peak yield of mudstone lags behind. The non-hydrocarbon gas productivity increases with temperature rise. The non-hydrocarbon gases are carbon dioxide, nitrogen gas and oxygen mainly. The productivity of carbon dioxide is significantly higher than other non-hydrocarbon gas productivities. The main hydrocarbon gas is methane. The productivity of methane increases when temperature rises. And the productivity increases obviously after 400 °C.