Helium and argon isotope geochemistry of natural gases in China's petroliferous basins

The age-accumulation effect of 40Ar in hydrocarbon source rocks was discussed in accordance with the decay law of radioactive elements. In terms of the mean values of 40Ar/36Ar, the old Sinian gas reservoirs (mean values of 40Ar/36Ar: 7009) were definitely distinguished from the Permian gas reservoirs (mean values of 40Ar/36Ar: 1017) in Weiyuan, Sichuan Province, and the gas source of the Permian gas reservoir (mean values of 40Ar/36Ar: 5222) in well Wei-7 with the Weiyuan structure is defined as the Sinian system. Based on the values of 40Ar/36Ar, the coal-type gases (The source rocks are of the C-P system; mean values of 40Ar/36Ar: 1125) are definitely distinguished from the oil-type gases (The source rocks are of the Tertiary system; mean values of 40Ar/36Ar: 590) in the Tertiary reservoirs of the Zhongyuan Oilfield. Besides, 40Ar/36Ar values also have a positive effect on the oil-source correlation of oil reservoirs in ancient hidden mountains. According to the crust-mantle interchange information reflected by 3He/4He values, petroliferous provinces in China can be divided into three major tectonic regions. (1) The eastern active region: The crust-mantle volatile matter exchanges actively, and the 3He/4He values are mainly around 10-6, partly around 10-7. (2) The central stable region: The 3He/4He values are all around 10-8. (3) The western sub-stable region: The 3He/4He values are mainly around 10-8, and around 10-7 on the edges of the basins. Helium contents of some gas wells in China’s eastern petroliferous region reach the industrial abundance (He≈0.05%–0.1%), the 3He/4He values reach 10-6, and the equivalent values for the mantle-source components in helium gas can reach 30%–50%. As viewed from this, a new type of crust-mantle composite helium resources has been proposed. Geneses of some CO2 gas reservoirs in the east of China and some issues concerning mantle-source methane were discussed in the light of the helium and carbon isotopes of CO2 and CH4 in natural gases. In the discussion on helium isotopic characteristics of inclusions in the reservoirs, it was discovered that the 3He/4He values are close to those in natural gases. That is to say, this phenomenon is related to regional tectonism. The 3He/4He, CO2/3He and CH4/3He data were used to discuss the tectonic activities of fault zones in a certain number of regions in China.

Laboratory Simulation of the Formation Process of Surface Geochemical Anomalies Applied to Hydrocarbon Exploration

The formation mechanisms and processes of geochemical anomalies used as proxies in surface geochemistry exploration （SGE） have not been well understood. Previous studies cannot realize 3D measurement of microseeping hydrocarbons from reservoirs to the surface, which made it difficult to understand the features and pathways of deep hydrocarbon microseepages. Understanding the processes of hydrocarbon microseepages will contribute to the acceptance and effectiveness of surface geochemistry. Based on a simplified geological model of hydrocarbon microseepages, including hydrocarbon reservoir, direct caprock, overlying strata and Quaternary sediments, this work established a 3D experimental system to simulate the mechanisms and processes of deep hydrocarbon microseepes extending to the surface. The dispersive halos of microseeping hydrocarbons in the subsurface were adequately described by using this 3D experimental system. Results indicate that different migration patterns of hydrocarbons above the point gas source within the simulated caprock and overlying strata can be reflected by the ratio of i-butane to n-butane （i-C4/n-C4）, which follow diffusion and infiltration （buoyancy） mechanisms. This is not the case for vertical measurement lines far from the point gas source. A vertical gas flow in the form of a plume was found during hydrocarbon microseepage. For sampling methods, the high-density grid sampling is favorable for delineating prospecting targets. Hydrocarbon infiltration or buoyancy flow occurs in the zones of infiltration clusters, coupling with a diffusion mechanism at the top of the water table and forming surface geochemical anomalies. These results are significant in understanding hydrocarbon microseepage and interpreting SGE data.

Origin of natural gases and their differences between the eastern and western parts of central Tarim Basin

The origin of natural gases in central Tarim Basin is very complicated and there has been no definite conclusion in this aspect. Based on the results of systematic research on their composition and carbon isotopic characteristics, natural gases in central Tarim Basin are composed mainly of hydrocarbon gas, Ordovician natural gas with the characteristics of crude oil-cracking gas, and Carboniferous natural gas not only originating from kerogen cracking, but also from oil cracking. There are significant differences in composition and carbon isotope of natural gases between the eastern and western areas. The causes for the differences in geochemical characteristics of natural gases are presented as follows: different thermal evolution degrees of organic matter. Natural gases in the western region may have generated from the Middle- Upper Ordovician source rocks, and natural gases in the eatern region may be derived from the Cambrian source rocks, which entered into high to over mature stages; the gases migrated from west to east and caused the different compositional and carbon isotopic characteristics of natural gases; difference in the strength of thermal sulfate reduction between the eastern and western parts, with the reduction in the eastern part being stronger than that in the western part.

Control effect of fluid entry pressure on hydrocarbon accumulation

The micromigration of oil-drive-water and gas-drive-water in oil and gas fields was studied,by using core slices and micro-experimental technology,and the migration processes and characteristics of oil and gas in pores and throats were observed,as well as entry pressures of oil/gas migration.Research shows that entry pressures of both oil-drive-water and gas-drive-water increase obviously as porosity decreases,and the statistical regularity observes the power function variation.However,there is a complex changing relationship between porosity and different entry pressure values of the two replacement processes,forming three curve sections,each representing a different accumulation significance.When the porosity is over 10%-12%,the difference between oil-drive-water and gas-drive-water entry pressures is small.Both oil and gas can migrate and accumulate in this kind of reservoir.The probabilities of oil and gas reservoir formation are nearly equal,forming conventional oil/gas pools.When porosity is between 5% and 10%-12%,the difference between the two is obvious,which indicates that this kind of reservoir can seal oil,but can also be a reservoir for gas,easily forming unconventional hydrocarbon pools(deep-basin gas pools).When porosity is less than 5%,the difference is indistinct and the entry capillary pressures show the same sealing function for oil and gas.In this condition,both oil and gas pools are difficult to form.Experimental results give a rational explanation for the difference of accumulation probability between deep-basin gas and deep-basin oil,and also for the mechanism of tight sand acting as cap rock.

Methane in soil gas and its transfer to the atmosphere in the Yakela condensed gas field in the Tarim Basin,Northwest China

In this study, by analyzing CH4 concentration and 613CCH4 in soil-gas profiles, the potentials of CH4 gas transfer from ground to atmosphere were studied at four representative sectors in the Yakela condensed gas field in the Tarim Basin, Xinjiang, China. These are： 1） the oil-gas interface sector, 2） fault sector, 3） oil-water interface sector, 4） an external area. Variation in CH4 in soil-gas profiles showed that CH4 microseepage resulted from the migration of subsurface hydrocarbon from deep-buried reservoirs to the earth＇s surface. It was found that CH4 from deep-buried reservoirs could migrate upwards to the surface through faults, fissures and permeable rocks, during which some CH4 was oxidized and the unoxidized methane remained in the soil or was emitted into the atmosphere. The lowest level of CH4 at the soil-gas profile was found at the CH4 gas-phase equilibrium point at which the CH4 migration upwards from deep-buried reservoirs and the CH4 diffusion downwards from the atmosphere met. The 613CcH4 and ethane, propane in soil gas exhibited thermogenic characteristics, suggesting the occurrence of CH4 microseepage from deep-buried reservoirs. A linear correlation analysis between CH4 concentrations in soil gas and temperature, moisture, pH, Eh, Ec and particle size of soil indicated that both soil Eh and soil temperature could affect CH4 concentration in soil gas while soil pH could indirectly influence soil methanotrophic oxidation via impacting soil Eh.

Multi-parameter quantitative assessment of 3D geological models for complex fault-block oil reservoirs

In the field of 3 D geologic modeling, researchers often pay more attention to modeling methods and workflows, but neglect the quantitative evaluation of models. If the evaluation is narrowed to the same reservoir type, the comparability and practicality of quantitative assessment will be emerging. The evaluation system should include three parts: data verification, geological understanding and process check. Data verification mainly involves testing the accuracy of local prediction with actual data, and geological understanding is to examine whether the global estimation honors geological principles and prior insights. Process check is also indispensable to avoid occasionality. To this end, we produced a set of assessment criteria, taking complex fault-block sandstone oil reservoir as an example. To be specific, thirteen characteristic parameters were totally selected, setting weights according to their rated importance, formulating three-level evaluation standards in a centesimal system for each characteristic parameter, and obtaining the final assessment based on the cumulative score. The results indicate that such evaluation can not only access the quality of the model objectively and comprehensively, but also identify the aspects in need of improvement through the deduction items.

Paleosalinity and Its Association with Organic Matter: A Case Study from the Eocene Shahejie Formation, Laizhou Bay Sag, Bohai Bay Basin (China)

Paleosalinity is vital for the paleoenvironmental reconstruction and affects the formation of source rock.The lower-middle sections of the third member of Eocene Shahejie formation(Es3M-L)constitute the most important source rock layer in Laizhou Bay Sag.However,the paleosalinity of the depositional water in which Es3M-L submembers are deposited remains unclear.A series of integrated experiments,including major and trace elements,X-ray diffraction,total organic carbon,and Rock-Eval,was performed to reveal the paleosalinity and its relationship with organic matter(OM).Various inorganic proxies(Sr/Ba,Rb/K,B/Ga,Walker’s paleosalimeter,Adam’s paleosalimeter,and Couch’s paleosalimeter)were employed to determine the paleosalinity of samples.Prominent differences existed in the proxies.Couch’s paleosalimeter is the most reliable and qualitative approach for Laizhou Bay Sag.Samples from the lake center(depocenter)and margin showed paleosalinities from 4.92 wt‰to 9.73 wt‰,suggesting a ubiquitous brackish(oligohaline-mesohaline)water body in the paleolake.Molybdenum enrichment in samples indicates an oxygen-depleted(suboxic or anoxic)condition.The increase in salinity has a certain but non-significant positive correlation with oxygen reduction.This condition may be attributed to the weak stratification of the water column in brackish water bodies.Moreover,paleosalinity has a weak and indirect relationship with OM accumulation during the deposition of Es3M-L submembers in Laizhou Bay Sag.

Effect of Shale Reservoir Characteristics on Shale Oil Movability in the Lower Third Member of the Shahejie Formation, Zhanhua Sag

To reveal the effect of shale reservoir characteristics on the movability of shale oil and its action mechanism in the lower third member of the Shahejie Formation(Es3l), samples with different features were selected and analyzed using N2 adsorption, high-pressure mercury injection capillary pressure(MICP), nuclear magnetic resonance(NMR), high-speed centrifugation, and displacement image techniques. The results show that shale pore structure characteristics control shale oil movability directly. Movable oil saturation has a positive relationship with pore volume for radius > 2 μm, as larger pores often have higher movable oil saturation, indicating that movable oil is present in relatively larger pores. The main reasons for this are as follows. The relatively smaller pores often have oil-wetting properties because of organic matter, which has an unfavorable effect on the flow of oil, while the relatively larger pores are often wetted by water, which is helpful to shale oil movability. The rich surface provided by the relatively smaller pores is beneficial to the adsorption of immovable oil. Meanwhile, the relatively larger pores create significant pore volume for movable oil. Moreover, the larger pores often have good pore connectivity. Pores and fractures are interconnected to form a complex fracture network, which provides a good permeability channel for shale oil flow. The smaller pores are mostly distributed separately;thus, they are not conducive to the flow of shale oil. The mineral composition and fabric macroscopically affect the movability of shale oil. Calcite plays an active role in shale oil movability by increasing the brittleness of shale and is more likely to form micro-cracks under the same stress background. Clay does not utilize shale oil flow because of its large specific surface area and its block effect. The bedding structure increases the large-scale storage space and improves the connectivity of pores at different scales, which is conducive to the movability of shale oil.

Presence of carboxylate salts in marine carbonate strata of the Ordos Basin and their impact on hydrocarbon generation evaluation of low TOC, high maturity source rocks

The total organic carbon(TOC)in the marine source rock of the Ordos Basin mostly ranges from 0.2%to 0.5%.The industrial standard commonly states that the TOC value has to be no less than 0.5%(0.4%for high mature or over-mature source rock)to form large petroleum reservoirs.However,gas source correlation indicates that the natural gas in the Jingbian gas field does receive contribution from marine source rocks.In order to determine the effect of carboxylate salts(or called as organic acid salts)on TOC in highly mature source rocks with low TOC value,we sampled the Ordovician marine source rock and the Permian transitional facies source rock in one drilled well in the southern Ordos Basin and performed infrared and GC-MS analysis.It is found that both kerogen-derived organic acids and carboxylate salt-conversed organic acids exist in both marine and transitional facies source rocks.The carboxylate salt-conversed organic acids mainly come from the complete acidification of carboxylate salts,which confirms the presence of carboxylate salts in the marine source rocks.Although the C16:O peak is the main peak for the organic acids both before and after acidification,the carboxylate salt-conversed organic acids have much less relative abundance ahead of C16:O compared with that of the kerogen-based and free organic acids.This observation suggests that the kerogen-based and free organic acids mainly decarboxylate to form lower carboxylic acids,whereas the carboxylate salt-conversed organic acids mainly break down into paraffins.By using calcium hexadecanoate as the reference to quantify the kerogen-derived and carboxylate salt-conversed organic acids,the high TOC(>2.0%)marine source rocks have low carboxylate salt content and the low TOC(0.2%–0.5%)marine source rocks contain high content of carboxylate salt.Therefore,for the marine source rocks with 0.2%–0.5%TOC,the carboxylate salts may be a potential gas source at high maturity stage.

Influences of water media on the hydrogen isotopic composition of natural gas/methane in the processes of gaseous hydrocarbon generation and evolution

The influences of water media on the hydrogen isotopic composition of organic-thermogenic natural gas were tested in three series of experiments on coal pyrolysis, with no water, deionized water (δDH2O=?58‰), and seawater (δDH2O=?4.8‰) added, respectively. The experimental results show that the productivities of H2 and CO2 obviously increased under hydrous condi tions and that the productivity of CH4 also remarkably increased in the high-evolution phase of hydrous experiments. Water was involved in the chemical reaction of hydrocarbon generation, and then the hydrogen isotopic composition of methane was affected. There is a linear correlation between the hydrogen isotopic composition of methane and its productivity, as reflected in the three series of experiments. In the case of the same CH4 productivity, the hydrogen isotopic composition of the methane produced in anhydrous experiments was the heaviest, that of the methane produced in seawater-adding experiments came se cond, and that of the methane produced in deionized water-adding experiments was the lightest. The hydrogen isotopic com position of natural gas/methane is affected by the following factors: 1) the characteristics of hydrogen isotopic composition of organic matter in source rocks, 2) the thermal evolution extent of organic matter, and 3) fossil-water media in the natural gas-generation period. The experimental results show that the influence of the fossil-water medium in the natural gas-generation period was lower than that of the other factors.

Fluid Inclusion and Geochemistry Studies of Calcite Veins in Shizhu Synclinorium,Central China:Record of Origin of Fluids and Diagenetic Conditions

Calcite veins in carbonate fracture have been investigated by petrographic, fluid inclusion, geochemical analyses and coupled with basin modeling techniques to provide useful insights into fluid activity and deformation conditions of the Cambrian to Triassic Shizhu synclinorium from the western region of Mid-Yangtze, central China. The results of the fluid inclusion microthermometry show a wide range of homogenization temperatures（78.6–215.5 °C） and salinities（0.18–23.11 wt.% NaCl equivalent）, indicating the formation under diverse fluid conditions. All the calcite veins have negative Ce anomalies, which are the typical characteristic of marine carbonate sediments; it is therefore plausible that calcite veins were precipitated from the marine basin fluid. The stable carbon isotopic compositions of calcites（δ^（13）CV-PDB=-2.5‰–4.26‰） and host limestones（δ^（13）CV-PDB=-3.56‰–5.80‰） are very similar with a correlation coefficient of 0.86, however, four calcites from the Lower Permian and Lower Triassic show lower δ^（13）C values relative to the host limestones, and they are depleted in total REE concentrations（∑REE ratio varies from 0.74 to 2.06）, suggesting the derivation of dissolved carbon from marine carbonates hosting the calcite veins and, less commonly, from the degradation of organic matter. Calculated δ^（18）O of the fluids-precipitating calcites（δ^（18）OV-SMOW=-0.41‰–14.42‰）, ^（87）Sr/^（86）Sr ratios varying in the range of coeval seawater and the distinct REE pattern simultaneously suggest calcite-forming fluids in each stratigraphic unit could have formed from the involvement of fluids that originated from coeval seawater and evolved through different degrees of water rock interaction. However, the presence of more radiogenic ^（87）Sr/^（86）Sr ratios than coeval seawater and pronounced positive Eu anomalies in calcites of Lower to Middle Ordovician rocks indicate that terrestrial input from upper strata mudstone and siliciclastic rocks could be involved in the precipitation of the Ordovician calcite. Fluid-inclusion data combined with burial and thermal history modeling indicate there was large-scale flow of evolved basinal fluids through the carbonate formation fractures spanning a time frame from 135 to 50 Ma（Early Cretaceous–Eocene）. Therefore, the geochemical characteristics of calcite veins can provide the basis for deformation events in Late Yanshanian and Early Himalayan orogeny.

Source and distribution of mercury in natural gas of major petroliferous basins in China

Based on the analysis of the natural gas samples of 146 wells from four major petroliferous basins of China,the source and distribution of mercury in natural gas in major petroliferous basins of China were identified.Studies have shown that the mercury concentration of natural gas in petroliferous basins of China varies widely,ranging from 0.01 to 4050μg/m^3.The gas well with the highest mercury concentration is in the Xushen gas field in the Songliao Basin.The mercury concentration in the craton basin is relatively low,and the secondary gas reservoir in the Tarim Basin has the lowest mercury concentration.In the rift basin,due to the presence of deep faults which cut the basement and mixing effects of deep fluids,the mercury concentration in natural gas may be abnormally high,e.g.the Xushen gas field in the Songliao Basin.In relatively stable basins where deep and large faults do not develop,mercury is primarily of organic origin.In rift basins where deep fluids are mixed with gas reservoirs,mercury in natural gas may mainly come from the deep fluids and is characterized by abnormally high mercury concentration and R/Ra values.

An Improved 3-D Ray Tracing Method Using Linear Traveltime Interpolation

An approach of three-dimensional seismic ray tracing is presented,which is derived from adopting two-dimensional linear traveltime interpolation（LTI）.By adjusting the forward process using the partition of grid interface,and backward step by considering more directions,the new approach is suitable for the application of three-dimensional models.The calculation results show that,with the same accuracy,the improved 3-D method is much faster than the method of traditional LTI directly applied in the three-dimensional case.