Jin Zhijun

Influences of Deep Fluids on Organic Matter of Source Rocks from the Dongying Depression, East China

Ten samples of source rocks from the Dongying depression were analysed by organic petrographic and geochemical methods in order to study the influences of deep fluids on organic matter of source rocks. The results indicate that the organic parameters show different variations under the influences of deep fluids. The extract yields increase in the samples from the strong fluid zone. The contents of saturated and aromatic hydrocarbon fractions are lower, whereas the contents of polar compound and asphalt fractions are higher in the samples from the strong fluid zone. The hydrogen from the deep fluids might react with organic matter, and resulted in the increase of the extract yields, or deep fluids as catalyses for hydrocarbon generation resulted in the increase of the extract yields. The maturity parameters decrease under the influences.

Phase states of hydrocarbons in Chinese marine carbonate strata and controlling factors for their formation

Chinese marine strata were mainly deposited before the Mesozoic. In the Tarim, Sichuan and Ordos Basins, the marine source rocks are made of sapropelic dark shale, and calcareous shale, and they contain type II kerogen. Because of different burial and geothermal histories, the three basins exhibit different hydrocarbon generation histories and preservation status. In the Tarim Basin, both oil and gas exist, but the Sichuan and Ordos Basins host mainly gas. The Tarim Basin experienced a high heat flow history in the Early Paleozoic. For instance, heat flow in the Late Cambrian varied between 65–75 mW/m2, but it declined thereafter and averages 43.5mW/m2 in the current time. Thus, the basin is a “warm to cold basin”. The Sichuan Basin experienced an increasing heat flow through the Early Paleozoic to Early Permian, and peaked in the latest Early Permian with heat flows of 71–77 mW/m2. Then, the heat flow declined stepwise to the current value of 53.2 mW/m2. Thus, it is a generally a high heat flow “warm basin”. The Ordos Basin has a low heat flow for most of its history (45–55 mW/m2), but experienced a heating event in the Cretaceous, with the heat flow rising to 70–80 mW/m2. Thus, this basin is a “cold to warm basin”. The Tarim Basin experienced three events of hydrocarbon accumulations. Oil accumulation formed in the late stage of Caledonian Orogeny. The generation and accumulation of oil continued in the Northern and Central Tarim (Tabei and Tazhong) till the late Hercynian Orogeny, during which, the accumulated oil cracked into gas in the Hetianhe area and Eastern Tarim (Tadong). In the Himalaya Orogeny, oil cracking occurred in the entire basin, part of the oil in the Tabei and Tazhong areas and most of the oil in the Hetianhe and Tadong areas are converted into gas. In the Sichuan Basin, another triple-episode generation and accumulation history is exhibited. In the Indosinian Orogeny, oil accumulation formed, but in the Yanshanian Orogeny, part of the oil in the eastern Sichuan Basin and most of the oil in the northeastern part was cracked into gas. In the Himalayan Orogeny, oil in the entire basin was converted into gas. The Ordos Basin experienced a double-episode generation and accumulation history, oil accumulation happened in the early Yanshanian stage, and cracked in the late stage. In general, multiple phases of heat flow history and tectonic reworking caused multiple episodes of hydrocarbon generation, oil to gas cracking, and accumulation and reworking. The phases and compositions of oil and gas are mainly controlled by thermal and burial histories, and hardly influenced by kerogen types and source rock types.

Developmental modes of the Neoproterozoic-Lower Paleozoic marine hydrocarbon source rocks in China

Based on the researches on rock type, the mode of occurrence, diagnostic minerals and creatures, the sedimentary geochemistry and organic facies of Chinese marine source rocks from wells and outcrops, and on the research findings of developmental modes of foreign marine source rock, the authors consider that it is impossible to objectively make clear the formation mechanism of hydrocarbon source rock with high organic matter abundance by either single mode of preservation or high organic matter productivity. According to the Chinese geological features, the formation mechanism of the Neoproterozoic-Lower Paleozoic marine source rock is generalized into four modes, namely, thermal water activity-upwelling flow-anoxic; carbonate gentle slope-upwelling flow; xerothermic climate-brine euxinic milieu; and humid climate-retained euxinic milieu; as the Lower Cambrian undercompensation basin organic facies (the Tarim Basin, South China and southwestern margin of North China), carbonate gentle lime mud bound organic facies (the Upper Ordovician in Tazhong region of the Tarim Basin and the Lower Silurian in the Upper Yangtze Platform), the Middle Cambrian evaporation laggon organic facies (the Tarim Basin and the Upper Yangtze Platform), enclosed undercompensation terrigenous bay organic facies (the Middle-Upper Ordovician in the west of the Tarim Basin, the Lower Silurian Long-maxi Formation in the Upper Yangtze platform). Chinese marine sedimentations with lower organic matter abundance are generalized into two modes of consumption-dilution mode of open epicontinental sea and depletion-dilution mode of supercompensation basin.

Discovery of low-mature hydrocarbon in manganese nodules and ooze from the Central Pacific deep sea floor

Extracts from manganese nodules and ooze from the Central Pacific deep sea floor were analyzed using the chromatogram-mass spectrum, and it was found that most of the biomarker molecules are of the low-mature type (some have characteristics of mature): the ratio of “A”/C is high between 11.4%–19.75%; CPI is 1.22–1.23; C31-22S/ (22S+22R) hopane is 0.59–0.60, Tm/Ts is 0.99–1.99; βa moretane/(aβ+βa) hopane is 0.12 – 0.14; C29 sterane 20S/(20S+20R) is 0.35 – 0.41; ββ/(ββ+αα) is 0.38 – 0.45; arene TA(I)/TA(I+II) is 0.16–0.21; methyl-phenanthrene index (MPI1) is 0.35–0.67. According to the geological settings of the sampling area and its organic geochemical characteristics, it is considered that the hydrothermal activities on the ocean floor facilitate the decomposition of organic matter in the sediment, which leads to the generation and migration of hydrocarbon into manganese nodules and ooze. This discovery is important for understanding the mechanisms of hydrocarbon generation in the ocean floor and for expanding the potential of oil and gas exploration in the ocean.

CH4/N2 Ratio as a Potential Alternative Geochemical Tool for Prediction of Thermal Maturity of Natural Gas in Tarim Basin

Abstract In this context, the bulk ratio of CH 4 /N 2 is examined as a potential alternative geochemical parameter for the assessment of thermal maturity of natural gas and compared to other previously published data. Open-system non-isothermal pyrolysis of low-mature coal from the Manjiaer sag, Tarim basin, yielded generation curves for methane and nitrogen. Analysis of the change of vitrinite reflectance indicates a two-stage process of thermal maturation with increasing temperatures. The relationship between R o and pyrolysis temperature could be expressed by the following equations: Stage I: R o = 0.0014 T + 0.109, r = 0.9931( R o R o = 0.0067 T −1.5855, r = 0.9996 ( R o > 0.6%). A kinetic interpretation of the characteristics of nitrogen and methane generation in humic coal during laboratory pyrolysis indicates that the bulk ratios of methane and nitrogen as thermal maturity parameters may be applied to assess the maturity of gas-sources. Thus, the maturity of the source rocks of natural gases in the Tarim basin was expressed in terms of CH 4 /N 2 ratios and compared with other geochemical natural gas parameters, such as stable isotopes. The predicted results were found to be consistent with the published data.

Distribution and Geochemical Characteristics of Hydrogen in Natural Gas from the Jiyang Depression, Eastern China

Hydrogen gas accelerates hydrocarbon generation, but little is known about its distribution and origin in petroliferous basins, which has hindered the further exploration. Taken the Jiyang Depression in eastern China as an example, this study collected natural gas from different tectonic units, and analyzed various geochemical characters including gas contents, and carbon and hydrogen isotopic composition. The result shows that: (1) hydrogen gas is widespread distributed, but its content is very low, which typically ranges from 0.01% to 0.1% in this region; (2) the ratios of H2/3He, indicative of the origins of hydrogen gas, suggest that mantle-derived hydrogen is dominant. Even in tectonically stable areas absent with deep fluid activities, there is also mantle-derived; (3) the isotopic composition of hydrogen falls in the range of −798‰ to −628‰ (relative to VSMOW standard). In areas with deep-derived fluids, the hydrogen gas has a similar isotopic composition with the previously documented deep-sourced gas, with lighter isotopic composition. In contrast, hydrogen gas has a heavier isotopic composition in relatively stable areas. The isotopic signatures suggest that there is a mixture of mantle- and crust-derived hydrogen gas in the relatively stable area, which is consistent with the H2/3He ratios. Therefore, it is clear that the hydrogen gas has a much wider distribution than found in the deep-derived fluid area, resulting in a much broader area with hydrogenating effect for resource rock. This understanding will provide new insights for hydrocarbon generation research and resource assessment in petroliferous basins.

Controls of tectonics on both sedimentary sequences and petroleum systems in Tarim Basin, northwest China

Various orders of sequences were recognized in the Tarim Basin from unconformities. Three mega-sequence groups, six mega-sequences, sixteen super-sequences and forty-two sequences were determined from the Sinian to the Quanternary. The mega-sequences and super-sequences were in accordance with the locally tectonic events occurring in both the north and the south margins of the Tarim plate. The global sea level changes only worked to control formations in the tectonically stable periods or in the low order sequences. The sequences had close relationship to the source rocks, reservoirs and cap rocks, and the tectonic events determined the migration, accumulation, and preservation of the hydrocarbon. The three mega-sequence group cycles, including the early cycle-the Sinian-middle Devonian, the middle cycle the upper Devonian-Triassic, and the late cycle-the Jurassic Quaternary, corresponded to three reservoir formation cycles. So, it can be concluded that the local tectonic events controlled both the sequences and the distribution of oil and gas in the Tarim Basin.

Prediction of the Distribution Range of Deep Basin Gas Accumulations and Application in the Turpan-Hami Basin*

Deep Basin Gas is short for deep basin gas accumulation. It is an abnormal gas accumulation whose formation conditions, trapping mechanism and distribution are different from those of normal gas accumulations. Deep basin gas accumulation is characterized by gentle dip angles, subnormal pressure, gas-water inversion and co-occurrence of reservoir and source rock. The fundamental conditions favourable to the formation of deep basin gas accumulation include a plentiful gas source, tight reservoir and tight seal under the reservoir. Two balances are the prerequisite for formation and preservation of deep basin gas accumulation. One is the force balance that occurs between the upward forces, including gas volume expansion pressure and buoyancy, and the downward forces including hydrostatic pressure and capillary pressure. The other is material balance that occurs between the supply amount of gas and the escaping gas. If the amount of gas charging the reservoir is more than that of escaping gas, the distribution range of the accumulation will expand up to the boundary limited by the force balance; and vice versa, a lower supply will cause shrinkage of the range. The force balance determines the theoretical maximum range of deep basin gas accumulation. In this range, gas expelled from the source rock can be accumulated to form a deep basin gas pool. The greater the amount of gas that is expelled from the source rock, the larger will be the distribution range of deep basin gas accumulation. Beyond this range, gas that is expelled from the source rock has no choice but to migrate under the force of buoyancy to form a normal gas accumulation. The equation of force balance predicting the theoretical maximum range of deep basin gas is L = f ( H S , D , Z m , , ∅ , α , T , R , S w , g , ρ g , ρ w ) . where, Sw ρw, g, ρg represent saturation of water in reservoir, density of water, acceleration of gravity and density of gas, respectively; T and R are, respectively, subsurface temperature of gas and gas constant; L represents the lateral distance from the depth of boundary force balance to the maximum depth of the depression centre. When the thickness of the reservoir(Hs), grain size of sandstone(D), porosity(Ø), and dip of strata(α) increase and maximum burial depth of reservoir(Zm) decreases, the likely distribution range of deep basin gas will shrink. In this paper, based on the mechanism of material balance, the equation calculating the distribution range of a deep basin gas pool in actual geological settings is L = f ( l r , H n , K T I , R O , C % , S R , Z m , X k , t ) It is shown that, in actual geological settings, the distribution range of deep basin gas accumulation will expand with better source conditions (or with an increase of thickness of source rock (Hn), abundance of organic matter(C%), kerogen type(KTI) and thermal evolution degree (Ro)) and with increase of burial rate (SR), burial depth(Zm) and salinity of formation water, but will shrink with increases of age of the reservoir(t), temperature(T), porosity(Ø), permeability (K) and dip of strata(). In the Xiaocaohu region and Well Taican 2 region of the Taibei sag in the Turpan-Hami Basin, stable structural settings, well-developed gas source, tight reservoir and feasible cover are favourable to form a deep basin gas reservoir. Drilling shows that there exist deep basin gas accumulations in Well Taican 2 region and Xiaocaohu sub-sag. For the gas layers drilled in the Jurassic Badaowan formation (J1b) and Xishanyao formation (J2x), there is subnormal pressure generally. The reservoirs outside the gas-bearing range in Hongtai and Gedatai gas field are tight and are interpreted as gas layers by logging and produce gas without water, and so belong to one part of a deep basin gas reservoir. Specially processed seismic data shows that there exists a large amount of natural gas in J1b and J2x of Well Taican 2 region. From the principles of force balance and material balance it is predicted in this paper that the distribution ranges of deep basin gas reservoir in J1b and J2x of Xiaocaohu sub-sag are 600km2 and 750km2, respectively, and the total reserves of natural gas should reach 11.3×1011m3. The Turpan-Hami Basin, located in northwest China, is of Mesozoic and Cenozoic age, and is a continental coal-bearing intermountain basin. Recently significant amounts of oil accumulations have been found in the Jurassic layer, and are thought be coal-derived oils, generated chiefly from coal-bearing layers of the Jurassic Badaowan formation (J1b) and Xishanyao formation (J2x) (Wu, 1996; 1997; Cheng, 1994; Huang, etc., 1995). Coal is a typical humic organic matter and, although it contains macerals of exinite etc. that generate oil, it mainly generates gas. The large oil accumulation that is found in the basin (in which the source rocks generate gas primarily) indicates that natural gas exploration has a wide realm and high prospectivity. We have studied the formation mechanisms of the natural gas reservoirs that have been found. The pressure and attitude features of the formation are different from those of a normal gas reservoir, and are the same as those of deep basin gas reservoirs reported by others (McMaster, 1983; Gant, 1983; Masters, 1993; Welte, et al, 1984; Gies, 1988; Masters, 1988; Yuan and Xu, etc, 1996; Rong, 1993; Li1 et al., 1997; Jin et al, 19982, Jin and Zhang 1999; Chen, 1998; Dai, 1983; Min et al., 1996; 1998). The conditions of accumulation are analyzed and evaluated with deep basin gas accumulation theory, based on which the potential distribution range of deep basin gas is predicted.

An approach to the present-day three-dimensional (3D) stress field and its application in hydrocarbon migration and accumulation in the Zhangqiang depression, Liaohe field, China

Abstract From the measurements of bore-hole breakout, hydrofracturing, and rock acoustic emission in the Zhangqiamg depression, Liaohe field, China, we have determined that the orientation of the maximum principal compressive stress is nearly east–west with a small angle of pitch (no more than 10°), and the regression equations of stress gradient with depth are σ 1 =8.359+0.0142 H ( r =0.96) and σ 3 =5.801+0.00437 H ( r =0.94). The present-day three-dimensional (3D) stress field of the Zhangqiang depression is approached using measured data and by 3D modeling. The approach shows that a full 3D crustal stress field analysis of an oil basin is consistent with the actual measurements. And then we use fluid potential or gradient to discuss the quantitative correlation between crustal stress and hydrocarbon migration and accumulation. The results show that low fluid potential areas surrounded by high regions are eligible for hydrocarbon accumulation and have been tested at the Keerkang oil field. The results also show that the distribution of favorable areas for hydrocarbon accumulation varies in different layers in space and is used in hydrocarbon exploration in the Zhangqiang depression. Therefore, the understanding of the 3D crustal stress field of a basin is essential for evaluating hydrocarbon migration and accumulation, and the technology and methodology developed here can be applied to other petroliferous basins.

Sedimentation Rate Rhythms:Evidence from Filling of the Tarim Basin,Northwest China

Variations of sedimentation rate within a basin over geologic time are a time series that can be filtered into several cyclic wave curves. Based on back-stripping and the empirical mode decomposition method, the cores from 14 wells in the Tarim Basin were selected to do filtering analysis. Four cycles or quasi-cycles (33 Ma, 64.4 Ma, 103.6 Ma, and 224 Ma) were obtained. Among these, the 33 Ma period, which was related to the internal earth activity, an external force, or a combination of the two, was the most obvious. The 64.4 Ma period corresponded to the solar system crossing the galaxy plane or the periodic melting of inner-earth material. The 103.6 Ma period was related with plate collisional tectonism around the Tarim Plate. The 224 Ma period was related to one galaxy year and may also be related to the aesthenospherical convection cycle.