Main Source Of Gas Research Articles

Oolitic Sedimentary Characteristics of the Upper Paleozoic Bauxite Series in the Eastern Ordos Basin and Its Significance for Oil and Gas Reservoirs

In recent years, great breakthroughs have been made in gas explorations of the Upper Paleozoic bauxite series in the Longdong area of the Ordos Basin, challenging the understanding that bauxite is not an effective reservoir. Moreover, studying the reservoir characteristics of bauxite is crucial for oil and gas exploration. Taking the bauxite series in the Longdong area as an example, this study systematically collects data from previous publications and analyzes the petrology, mineralogy, oolitic micro-morphology, chemical composition, and other sedimentary characteristics of the bauxite series in the study area using field outcrops, core observations, rock slices, cast slices, X-ray diffraction analysis, scanning electron microscopy and energy spectra, and so on. In this study, the oolitic microscopic characteristics of the bauxite reservoir and the significance of oil and gas reservoirs are described. The results show that the main minerals in the bauxite reservoir are boehmite and clay minerals composed of 73.5–96.5% boehmite, with an average of 90.82%. The rocks are mainly bauxitic mudstone and bauxite. A large number of oolites are observable in the bauxite series, and corrosion pores and intercrystalline pores about 8–20 μm in size have generally developed. These pores are important storage spaces in the reservoir. The brittleness index of the bauxite series was found to be as high as 99.3%, which is conducive to subsequent mining and fracturing. The main gas source rocks of oolitic bauxite rock and the Paleozoic gas series are the coal measure source rocks of the Upper Paleozoic. The oolitic bauxite reservoirs in the study area generally have obvious gas content, but the continuity of the planar distribution of the bauxite reservoirs is poor, providing a scientific basis for studying bauxite reservoirs and improving the exploratory effects of bauxite gas reservoirs.

Acoustic evidence of hydrocarbon release associated with the Spitsbergen Transform Fault, north of the Molloy Ridge, Fram Strait

Hydrocarbon gases formed from biotic and abiotic processes are released through the seafloor at different locations around the world. They have been widely observed directly in video and photo data, and indirectly on echosounder data. Even though biotic gas generation is a very common process, abiotic gas generation is limited to regions where serpentinization of ultramafic rocks occur. Indications of abiotic gas occurrences are therefore sparse and much speculated upon. Here, we investigated the Spitsbergen Transform Fault, the Molloy Ridge, the Molloy Deep, and the Molloy Transform Fault/Fracture Zone, (a transform fault-bounded pull-a-part region offshore western Svalbard) where both processes may be active. Multiple acoustic gas flares, ∼1,770 and ∼3355 m high above the seafloor (tallest ever recorded), were observed indicating active migration and seepage of hydrocarbons. The proximity to the mid oceanic ridge and the documented high heat flow suggests the influence of high temperatures on organic-rich sedimentary deposits. Deep seismic data and other geological information available indicate that the main source of gas could be from thermal cracking of either pre- or syn-rift source rock organic material, potentially mixed with methane from serpentinization of mantle rocks (peridotites). Correlation with seismic stratigraphy from Ocean Drilling Program (ODP) Sites 910 and 912 on the adjacent Yermak Plateau suggests that the sedimentary source rocks may be present at the northern flank of the Molloy Ridge and within the deep graben along the Spitsbergen Transform Fault. The ∼3 km thick sedimentary succession in high heat flow zones within the transform fault and the active bounding faults allow generation and migration of hydrocarbons to the seafloor and sustains present day seepage.

Key Problems and Countermeasures in CO2 Flooding and Storage

AbstractBased on literature research in combination with the practice of CO2 flooding and storage in Jilin Oilfield, this study assesses the key problems in CO2 flooding and storage, proposing the corresponding countermeasures from five aspects of CO2 gas source condition, namely geological condition evaluation, scheme design incoordination with other production methods, economic and effectiveness evaluation, together with dynamic monitoring and safety evaluation. The results show that CO2 flooding is the most economic and effective CO2 storage method. In eastern China, inorganic origin CO2 gas reservoirs are widely developed and are especially the most enriched in the Paleozoic carbonate rock strata and the Cenozoic Paleogene–Neogene system, which provide a rich resource base for CO2 flooding and storage. In the future, CO2 generated in the industrial field will become the main gas source of CO2 flooding and storage. The evaluation of geological conditions of oil and gas reservoirs is the basis for the potential evaluation, planning scheme design and implementation of CO2 flooding and storage. CO2 storage should be below the depth of 800 m, the CO2 flooding and storage effects in low‐permeability oil reservoirs being the best. CO2 geological storage mechanisms primarily consist of tectonic geological storage, bound gas storage, dissolution storage, mineralization storage, hydrodynamic storage and coalbed adsorption storage. The practice of CO2 flooding and storage in Jilin Oilfield demonstratesthat the oil increment by CO2 flooding is at least 24% higher than by conventional water flooding. The most critical factor determining the success or failure of CO2 flooding and storage is economic effectiveness, which needs to be explored from two aspects: the method and technology innovation along with the carbon peaking and carbon neutrality policy support. After CO2 is injected into the reservoir, it will react with the reservoir and fluid, the problem of CO2 recovery or overflow will occur, so the dynamic monitoring and safety evaluation of CO2 flooding and storage are very important. This study is of great significance to the expansion of the application scope of CO2 flooding and storage and future scientific planning and deployment.

Nature of Hydrocarbon Fluids at the Fields in the North of Western Siberia: the Geochemical Aspect

The paper presents original results of comprehensive geochemical studies of samples of oils, condensates, gases, core, and cuttings from wells drilled in the north of Western Siberia. The studies involved chromatographic and mass spectrometric determinations of the molecular and isotopic composition of the oils, gases, condensates, and rock extracts. Analysis of the results, considered together with literature data, made it possible to draw conclusions regarding the source of the hydrocarbons and the mechanism of formation of their accumulations. Information on the molecular and isotopic composition of the fluids and the distribution of their accumulations and fields in the sedimentary cover shows that most of them are of polychronic and polygenic origin. Features of the molecular and isotopic composition of the fluids make it possible to evaluate the contribution of various sources to the formation of hydrocarbon accumulations. The composition of their liquid component was formed as a result of the generation of hydrocarbons by the organic matter of Jurassic source rocks. The Lower and Middle Jurassic rocks with non-marine organic matter also made a significant contribution to the formation of the gas component of deposits in the north of Western Siberia, whereas the Cretaceous rocks generated only dry gas and were likely the main source of gas for the giant fields, whose methane has a light carbon isotope composition. The use of the isotopic composition of carbon in combination with molecular parameters makes it possible to clarify the conditions under which a particular field was formed and to elucidate the migration pathways and distances of hydrocarbon fluids to their accumulation sites

Generation and geochemical signatures of natural gas from solid bitumen: Implications from closed and stepwise semi-open pyrolysis experiments

Solid bitumen has been acknowledged as an important source of overmature shale gas. However, the gas generation potential, chemical signatures and carbon isotopic compositions of natural gas derived from solid bitumen in an overmature hydrocarbon system are not well-understood with respect to various geological conditions. In this study, a relatively low-maturity solid bitumen from Cambrian reservoirs in the northwest Sichuan Basin was pyrolyzed in both closed and stepwise, semi-open systems. In the closed system, methane generated in the overmature thermal stage is dominated by the secondary cracking of wet gas and cumulative methane carbon isotopic values that are 4.4‰–14.8‰ lighter than the carbon isotope composition of the original solid bitumen. In semi-open systems, the gas is predominantly generated from residual solid bitumen and has wetness (i.e., C2–C5/C1–C5 by volume) values of generally less than 1%. At the same thermal maturity levels, the carbon isotope composition of methane in various semi-open systems is 4.4‰–10.0‰ heavier than those in the closed system and may also be isotopically heavier than the carbon isotope value of the original solid bitumen. The present study also illustrates that the calculated gas yields and methane carbon isotopes within a certain thermal maturity range in the closed system cannot be compared with those from residual solid bitumen as measured in the corresponding semi-open systems. This highlights the need to conduct specific semi-open pyrolysis experiments to investigate the late gas generation potential and geochemical signatures of natural gas from solid bitumen when the geological system is not a closed system. By comparing the above-mentioned results with the geochemical characteristics of Wufeng-Longmaxi shale gas from the Changning and Jiaoshiba gas fields of the Sichuan Basin, southwest China, it is suggested that the shale gas examined in this study is most likely generated in semi-open systems rather than in a closed system. In other words, the early-generated gas has been expelled from the shales, leaving the late-generated gas from residual solid bitumen and/or kerogen as the main gas source in the present hydrocarbon system.

Palaeosedimentary Environment and Formation Mechanism of High-Quality Xujiahe Source Rocks, Sichuan Basin, South China

AbstractTriassic Xujiahe source rocks, the main gas source of shallow tight gas, are the most typical continental coal-bearing source rocks in the Sichuan Basin, South China. However, the organic matter enrichment section cannot be identified easily, leading to limited progress in the exploration of coal-bearing tight gas. This paper reveals the main controlling factors of the organic matter enrichment, reconstructs the evolution process of the Xujiahe palaeosedimentary environment, proposes a dynamic enrichment mechanism of the organic matter, and determines the organic matter enrichment section of the high-quality coal-bearing source rocks by geochemical characteristics of the source rocks, major elements, and trace elements. The results show that the Xujiahe sedimentary environment can be divided into a fluctuating stage of transitional sedimentation, stable stage of transitional sedimentation, fluctuating stage of continental sedimentation, and stable stage of continental sedimentation. The Xujiahe source rocks were featured with high-quality coal-bearing source rocks with high total organic carbon and maturity and good parent material in the stable stage of transitional sedimentation and fluctuating stage of continental sedimentation, in which the water was connected with the Palaeo-Tethys Ocean with abundant terrestrial organisms. The water was shallow in the fluctuating stage of transitional sedimentation with a low sedimentation rate, leading to poor organic matter enrichment. The Palaeo-Tethys Ocean withdrew westward from the Yangtze plate in the late period of the fluctuating stage of continental sedimentation, leading to the absence of algae and dinosteranes and a decrease in biological productivity in the stable stage of continental sedimentation. Therefore, high terrestrial inputs and biological productivity and high sedimentation rate were conducive to the organic matter preservation in the coal-bearing source rocks.

Phase Behavior in Nanopores and Its Indication for Cyclic Gas Injection in a Volatile Oil Reservoir from Duvernay Shale

Abstract Duvernay shale spans over 6 million acres with a total resource of 440 billion barrels’ oil equivalent in the Western Canada Sedimentary Basin (WCSB). The oil recovery factors typically decrease with the decreasing of gas-oil ratio (GOR) in oil window of Duvernay shale. The volatile oil recovery factors are typically 5–10%. Enhanced oil recovery technologies should be applied to improve the economics of the reservoirs. In this paper, the volatile oil from the Duvernay shale was taken as an example for phase behavior study. We analyzed the nanopore confinement on phase behavior and physical properties of Duvernay shale oil. The shift of critical properties was quantified within nanopores. With the confinement of nanopores, the viscosity, density, and bubble point pressure of the oil decrease with the shrinking of the pore size. Minimum miscibility pressure (MMP) was calculated for different injected gases. The MMP from high to low is N2>CH4>lean gas>rich gas>CO2. In the case of injecting the same gas component, the MMP decreases as the pore size decreases. The wellhead rich gas is suggested to be the main gas source for gas injection in Duvernay shale. The formation pressure should be rapidly increased to the MMP and maintained close to it, which would help to improve the effect of gas injection and enhance shale oil recovery. This paper can provide critical insights for the research of shale oil gas injection for enhanced oil recovery.

Characteristics of natural gas accumulation in the Cambrian weathered crust in southwestern Ordos Basin

The Cambrian weathered crust formed in the Early Paleozoic central paleouplift of the Ordos Basin and its periphery has always been a key target for oil and gas exploration, and important breakthroughs in oil and gas exploration have been made there. In order to further accelerate the process of natural gas exploration in this area, this paper based on systematic analysis of source-reservoir assemblage and trap type in the Cambrian weathered crust in southwestern Ordos Basin, and then evaluates its natural gas exploration potentials and favorable exploration zones. The following research results are obtained. First, the Upper Paleozoic coal-measure source rocks in the basin is the main gas source rocks, forming a source-reservoir assemblage of “upper source and lower reservoir” with Cambrian reservoir. Second, the types of the reservoir in the Cambrian weathered crust are mainly dolomite intercrystalline (dissolution) pores and karst fractures and vugs, whose development is controlled by grain shoal microfacies and karstification in the weathered crust stage, respectively. Third, the traps in the Cambrian weathered crust are mainly lithologic-stratigraphic traps, which were formed in the tectonic uplifting setting of the eastern Ordos Basin during the Yanshanian. There are geological conditions of lithologic and stratigraphic barriers in the updip direction, which is beneficial to the short-distance natural gas migration and accumulation. In conclusion, Huanxian-Zhengning area on the east margin of the central paleouplift in southwestern Ordos Basin is a favorable exploration zone of Cambrian weathered crust gas reservoirs, and the Middle Cambrian Zhangxia Formation and Upper Cambrian Sanshanzi Formation are favorable intervals of oil and gas exploration.

P-047. Elevated placental histone H3K4 methylation via upregulated histone methyltransferases in preeclampsia and its possible involvement in hypoxia-induced pathophysiology

The Cambrian weathered crust formed in the Early Paleozoic central paleouplift of the Ordos Basin and its periphery has always been a key target for oil and gas exploration, and important breakthroughs in oil and gas exploration have been made there. In order to further accelerate the process of natural gas exploration in this area, this paper based on systematic analysis of source-reservoir assemblage and trap type in the Cambrian weathered crust in southwestern Ordos Basin, and then evaluates its natural gas exploration potentials and favorable exploration zones. The following research results are obtained. First, the Upper Paleozoic coal-measure source rocks in the basin is the main gas source rocks, forming a source-reservoir assemblage of “upper source and lower reservoir” with Cambrian reservoir. Second, the types of the reservoir in the Cambrian weathered crust are mainly dolomite intercrystalline (dissolution) pores and karst fractures and vugs, whose development is controlled by grain shoal microfacies and karstification in the weathered crust stage, respectively. Third, the traps in the Cambrian weathered crust are mainly lithologic-stratigraphic traps, which were formed in the tectonic uplifting setting of the eastern Ordos Basin during the Yanshanian. There are geological conditions of lithologic and stratigraphic barriers in the updip direction, which is beneficial to the short-distance natural gas migration and accumulation. In conclusion, Huanxian-Zhengning area on the east margin of the central paleouplift in southwestern Ordos Basin is a favorable exploration zone of Cambrian weathered crust gas reservoirs, and the Middle Cambrian Zhangxia Formation and Upper Cambrian Sanshanzi Formation are favorable intervals of oil and gas exploration.

Research on Gas Treatment Technology in The Work Surface of Dasher Coal Mine

Based on the principle of gas formation on the coal mining work surface, the article analyzes the main source of gas in the mining area of Dashe coal mine, finds out all kinds of problems existing in the pumping of the upper angle intring tube, and summarizes the real reasons for the backwind of the work surface and the gas exceeding the limit of the upper angle. In view of these reasons, combined with the principle of the formation of the upper angle gas, the mine on the upper angle intring process construction of the intring depth, height and interception area of the investigation, to obtain the best pumping value under different conditions, and according to the results of the inspection in the 21704 work surface test and transformation, and achieved a better pumping effect; According to the test results, the field effectively controls the work surface and the upper angle gas exceeding the limit, ensures the safe production of the work surface and the mine, and provides reference and reference for the treatment of the angle gas on the work surface under the same type of condition.

Resource potential of the Jurassic gas system, northern margin of the Qaidam Basin, northwestern China

The main source rocks, hydrocarbon generative subbasins, hydrocarbon generation periods, resource potential, and the relationship between the trap evolution history and hydrocarbon generation history are important problems associated with oil and gas exploration. In this study, we develop a three-dimensional geological model with respect to the Mesozoic and Cenozoic strata of the northern margin of the Qaidam Basin based on the most recent geological data. Using this model, the burial depth, temperature, maturity, and gas generation history of the source rock, the plane diagram of the source-rock current maturity, the gas generation intensity map, and the amount of gas generation during each geological period and within different subbasins can be obtained. Based on the obtained maps, we can state that the maturity of the source rock controls the distribution of natural gas (i.e., natural gas is located within and in the vicinity of mature and highly mature source rocks). We also observed the following: (1) the Lower Jurassic section is the main gas source rock; (2) the Yibei subbasin is the main hydrocarbon generative subbasin, followed by the Kunteyi, Pingdong, and Lenghu subbasins; (3) the main gas generation period is after the upper member of the lower Ganchaigou Formation deposition, with maximum gas generation occurring during the upper Ganchaigou Formation deposition and gradually decreasing thereafter—the majority of the structures in the inner basin are formed after lower Youshashan Formation deposition, demonstrating the tectonic activity coincided with periods of natural gas formation; and (4) the amount of natural gas resource becomes 1.23 trillion cubic meters. From these analyses, we can demonstrate that the late tectonic belts formed in the four gas-generating subbasins exhibit considerable promise for exploration.

Geochemical characteristics and source analysis of natural gas in the saline lacustrine basin in the Western Qaidam basin

This paper analyzed the geochemical characteristics and the sources of natural gas in the western Qaidam Basin based on isotopes and gas composition. The natural gas in the western Qaidam Basin is mainly comprised of hydrocarbon gases, including sapropelic, humic and mixed gas. In the southwestern Qaidam Basin, the main gas is sapropel gas, with some mixed gas and a small amount of humic gas. In contrast, the northwestern Qaidam Basin contains mainly humic gas, some mixed gas, and a small amount of sapropel gas. The dryness coefficient varies between 0.6 and 0.95. The carbon isotopes of methane, ethane, and propane are distributed between −32.9‰ ~ −51.4‰, −34.2‰ ~ −22.4‰, −30‰ ~ −17.4‰, respectively. The calculated Ro value of the natural gas is between 0.5% and 1.87%. In general, the natural gas shows the characteristics of high dryness coefficient, heavy carbon isotopes, and high thermal maturity. The gas-source correlation makes it clear that the main hydrocarbon source rocks in the western Qaidam Basin are the lower Ganchaigou (E3), the upper Ganchaigou (N1) and the lower Youshashan formations (N21). The gas-producing layers in the northwestern Qaidam Basin are primarily from the lower Ganchaigou (E3), the lower Youshashan (N21), and the upper Youshashan formations (N22). The primary gas source rocks are the lower Ganchaigou (E3), the upper Ganchaigou (N1), and the lower Youshashan formations (N21). The main gas-producing layers in the southwestern Qaidam Basin are the lower Ganchaigou (E3), the upper Ganchaigou (N1), the lower Youshashan (N21) and the upper Youshashan formations (N22), with the main gas source rocks being the lower Ganchaigou Formation (E3).

The geological process for gas hydrate formation in the Qilian Mountain permafrost

The Qilian Mountain permafrost is the only place where gas hydrate occurs onshore China at present and its gas hydrate distribution is very complex and irregular. What patterns affecting the accumulation of gas hydrate or what process controlling the formation of gas hydrate are not clear in the study area. Aiming at a gas hydrate geological system, the geological process of gas hydrate formation was studied, based on geological data and analytical results obtained from drilling wells in the Qilian Mountain permafrost. As a result, three stages for the geological process of gas hydrate formation are put forward in the study area. During the late Mid-Jurassic, the upper Triassic generated and provided a major gas source for gas hydrate, secondarily in combination with gas associated with oil generated from the middle Jurassic. The main gas source migrated upward via faults of F1 and F2, partly and occasionally mixed with the coal-bed methane and the microbial methane produced in the shallow strata. It was blocked jointly by thrust faults and thick mudstone or oil shale to be initially accumulated in gas reservoir. From Cretaceous to Pleistocene, the sedimentary strata experienced erosion and the initial gas accumulation turned into residual gas after series of the Qinghai-Tibet plateau uplift. Since the early middle Pleistocene, glaciations formed a gas hydrate stability zone (GHSZ) and the residual gas was coupled with GHSZ to form gas hydrate subsequently. Hence three patterns for the coupling of the residual gas with GHSZ are summarized in the study area. When the residual gas happened to lie within GHSZ, the residual gas directly formed gas hydrate, which was indicated by the drilling results that gas anomalies were encountered within GHSZ as well as occurrences of gas hydrate in the field. When the residual gas was below GHSZ, the residual gas would continually migrate into GHSZ to form gas hydrate, which was indicated by the drilling results that gas anomalies had ever been encountered even if below GHSZ as well as occurrences of gas hydrate within GHSZ in the field. When the residual gas was above GHSZ, the residual gas remained or escaped, which was indicated by the drilling results that gas anomalies even with a high pressure abnormity were encountered in the shallower strata above GHSZ without occurrences of gas hydrate within GHSZ in the field.

Carbon isotopic characteristics of CH4 and its significance to the gas performance of coal reservoirs in the Zhengzhuang area, Southern Qinshui Basin, North China

To better understand the law of gas generation, migration and accumulation of the No. 3 coal seam in the Zhengzhuang (ZZ) area, Southern Qinshui Basin, North China, isotopic geochemical experiments, including determination of the molecular and isotopic compositions of coalbed gas and the hydrogen and oxygen isotope decompositions of the coalbed methane (CBM) co-produced water, as well as the geological and hydrogeological surveys, were conducted. The results reveal that CBM from the No. 3 coal seam is dominated by CH4 (46.5–99.54 vol%) and the carbon isotope ratio of the produced CH4 (δ13C1) ranges from −28.7‰ to −57.2‰. Secondary thermogenic CH4 caused by a tectonic thermal event in the Yanshan Epoch is the main gas source, with a small amount of secondary biogenic gas generated from methyl-type fermentation. The carbon isotope is fractionated due to the terrain change of the No. 3 coal seam, a discrepancy in internal structures of basin and the flushing of the groundwater. Geological and hydrogeological information shows that fluid pressure traps for gas preservation will easily form in the northern and eastern deep stagnation areas, or local syncline in the central part. Based on the experimental data and CBM well data, the gas content and gas saturation have a logarithmic correlation with δ13C1. These investigations may serve the exploration of favorable zones for gas accumulation and exploitation of CBM with the geochemistry and carbon isotope composition of CH4 in the study area.

Geochemical characteristics and origin of natural gas in southern Jingbian gas field, Ordos Basin, China

Jingbian gas field is yet the only Lower Paleozoic-hosted large gas field discovered in Ordos Basin. However, much debate still exists regarding the type and main source of natural gas in the Lower Paleozoic units. Previous studies on Jingbian gas field have mainly focused on the central and northern regions, whereas few studies have addressed the southern part. Basing on natural gas components and carbon isotope compositions of 33 gas samples from 28 wells in southern Jingbian gas field, we investigated the main gas source and phenomenon of carbon isotope reversal. The results indicate that natural gas from the Upper Paleozoic and Lower Paleozoic units are all at the high-mature and over-mature stages, with average dryness coefficients (C1/C1-4) of 0.982 and 0.996, respectively. The Upper Paleozoic natural gas primarily comprises coal-derived gas from Carboniferous-Permian units, whereas the composition of the Lower Paleozoic natural gas is mostly a mixture of Upper Paleozoic coal-derived gas with additional oil-type gas produced by Upper Paleozoic marine limestone. The phenomenon of carbon isotope reversal mainly results from downward diffusion and migration of the mixed coal-derived gases; moreover, in the Upper Paleozoic unit, it is also related to secondary cracking.

Determination of in-situ stress orientation and subsurface fracture analysis from image-core integration: an example from ultra-deep tight sandstone (BSJQK Formation) in the Kelasu Belt, Tarim Basin

Present-day stress state is significant for petroleum industry and prediction of stress-related geohazards. The Kelasu Belt, located between Southern Tianshan and the bank-land of the Tarim Basin, is a main gas source in China and is extremely active during Himalayan movement. Predicting the in-situ stress of the BSJQK Formation in the Kelasu Belt is difficult due to the ultra-deep tight sandstone reservoir (5500–8500m depth), with pervasively developed fractures, surrounded by multi-detachment layers and complicated structural association. In this study, we first analyzed the present-day maximum horizontal stress in the BSJQK Formation using imaging logs (FMI-HD, OBMI, EI and CBIL), then carried out the fracture interpretation based on core-image calibration, finally evaluated their hydraulic conductivity integrating well testing, petrophysical experiments and logging interpretation. The average SHmax orientation in wells B, C, D and E in the Kelasu Belt correspond to 124.76°N (±8.5°), 92.86°N (±4.3°), 143.28°N (±7.1°) and 180.89°N (±4.5°), respectively, which coincides well with the result derived from the focal mechanism solution. The stratigraphic attitude and boundary structure may control the variation of SHmax orientation. Fracture attitude in wells B, C, D and E correspond to 70°/26°N, 54°/346°N, 81°/239°N and 76°/253°N, respectively and intersect SHmax at an angle less than 29°. Fracture could increase formation permeability with 1–3 order of magnitudes and provides the main channel for gas migration. Furthermore, the calculation of “Gas Productivity Index per Meter” indicates that fracture density is closely related with gas productivity, which will guide the next fracturing intervals. The N-S or NEE-SWW could be the preferable orientations for drilling trajectory design of horizontal wells.

Geological Conditions and Prospect Forecast of Shale Gas Formation in Qiangtang Basin, Qinghai‐Tibet Plateau

Abstract:The presence of shale gas has been confirmed in almost every marine shale distribution area in North America. Formation conditions of shale gas in China are the most favorable for marine, organic‐rich shale as well. But there has been little research focusing on shale gas in Qiangtang Basin, Qinghai‐Tibet Plateau, where a lot of Mesozoic marine shale formations developed. Based on the survey results of petroleum geology and comprehensive test analysis data for Qinghai‐Tibet Plateau, for the first time, this paper discusses characteristics of sedimentary development, thickness distribution, geochemistry, reservoir and burial depth of organic‐rich shale, and geological conditions for shale gas formation in Qiangtang Basin. There are four sets of marine shale strata in Qiangtang Basin including Upper Triassic Xiaochaka Formation (T3x), Middle Jurassic Buqu Formation (J2b), Xiali Formation (J2x) and Upper Jurassic Suowa Formation (J3s), the sedimentary types of which are mainly bathyal‐basin facies, open platform‐platform margin slope facies, lagoon and tidal‐flat facies, as well as delta facies. By comparing it with the indicators of gas shale in the main U.S. basins, it was found that the four marine shale formations in Qiangtang Basin constitute a multi‐layer distribution of organic‐rich shale, featuring a high degree of thickness and low abundance of organic matter, high thermal evolution maturity, many kinds of brittle minerals, an equivalent content of quartz and clay minerals, a high content of feldspar and low porosity, which provide basic conditions for an accumulation of shale gas resources. Xiaochaka Formation shale is widely distributed, with big thickness and the best gas generating indicators. It is the main gas source layer. Xiali Formation shale is of intermediate thickness and coverage area, with relatively good gas generating indicators and moderate gas formation potential. Buqu Formation shale and Suowa Formation shale are of relatively large thickness, and covering a small area, with poor gas generating indicators, and limited gas formation potential. The shale gas geological resources and technically recoverable resources were estimated by using geologic analogy method, and the prospective areas and potentially favorable areas for Mesozoic marine shale gas in Qiangtang Basin are forecast and analyzed. It is relatively favorable in a tectonic setting and indication of oil and gas, shale maturity, sedimentary thickness and gypsum‐salt beds, and in terms of mineral association for shale gas accumulation. But the challenge lies in overcoming the harsh natural conditions which contributes to great difficulties in ground engineering and exploration, and high exploration costs.

Understanding measured water rotational temperatures and column densities in the very innermost coma of Comet 73P/Schwassmann–Wachmann 3 B

Direct sublimation of a comet nucleus surface is usually considered to be the main source of gas in the coma of a comet. However, evidence from a number of comets including the recent spectacular images of Comet 103P/Hartley 2 by the EPOXI mission indicates that the nucleus alone may not be responsible for all, or possibly at times even most, of the total amount of gas seen in the coma. Indeed, the sublimation of icy grains, which have been injected into the coma, appears to constitute an important source. We use the fully-kinetic Direct Simulation Monte Carlo model of Tenishev et al. (Tenishev, V.M., Combi, M.R., Davidsson, B. [2008]. Astrophys. J., 685, 659−677; Tenishev, V.M., Combi, M.R., Rubin, M. [2011]. Astrophys. J., 732) to reproduce the measurements of column density and rotational temperature of water in Comet 73P-B/Schwassmann–Wachmann 3 obtained with a very high spatial resolution of ∼30km using IRCS/Subaru in May 2006 (Bonev, B.P., Mumma, M.J., Kawakita, H., Kobayashi, H., Villanueva, G.L. [2008]. Icarus, 196, 241−248). For gas released solely from the cometary nucleus at a heliocentric distance of 1AU, modeled rotational temperatures start at 110K close to the surface and decrease to only several tens of degrees by 10–20 nucleus radii. However, the measured decay of both rotational temperature and column density with distance from the nucleus is much slower than predicted by this simple model. The addition of a substantial (distributed) source of gas from icy grains in the model slows the decay in rotational temperature and provides a more gradual drop in column density profiles. Together with a contribution of rotational heating of water molecules by electrons, the combined effects allow a much better match to the IRCS/Subaru observations. From the spatial distributions of water abundance and temperature measured in 73P/SW3-B, we have identified and quantified multiple mechanisms of release. The application of this tool to other comets may permit such studies over a range of heliocentric and geocentric distances.

Recoverable Potential of Coalbed Methane in the Wangying-Liujia Depression, Fuxin Basin, China

The Wangying-Liujia depression in the Fuxin basin covers a 20 km2 area and has abundant coalbed methane resource with in-place gas resource 51.81 × 108 m3. Compared with the basins where coalbed methane (CBM) development is successful, the recoverable potential of CBM is evaluated in the investigated district. In the Lower Cretaceous Fuxin Formation, the coal seams are thick (averagely 35.21 m – 42.96 m), the coal adsorption capacity is comparatively high with about 18∼34 m3/t, and the gas content is relatively high (8 m3/t – 10 m3/t). Vertical lithological sealing, lateral fault sealing and hydrodynamics are favorable for the preservation of CBM. Thermogenic gas generated at the end of early Cretaceous and Himalayan Orogeny is the main gas source. Secondary biogenic gas generated from the end of the Cretaceous to now increases gas content. All these provide resource basis for CBM development, and the recoverable resources is 15.543 × 108 m3. Though the permeability is low (well test 0.323 md – 0.469 md), coal can be fractured to improve the reservoir permeability. The coal reservoir is saturated gas or oversaturated, and the ratio of critical pressure to reservoir pressure is high (>0.74), which indicates that a little pressure need be decreased to make CBM desorbed from coal matrix and gas production. In one word, there are preferable recoverable potential in Wangying-Liujia depression, especially in the area limited by Piangan F2 fault, Liujia F2 and β5–2 dike. At present, 17 CBM production wells with 50 000 m3 per day operate in this area.

Gas dynamics modelling for particle accelerators

Design of an accelerator vacuum chamber requires an input from different scientific disciplines such as surface science, material science, gas dynamics, particle beam dynamics, and many others. Although vacuum scientists work on the boundary field between these disciplines, gas dynamics is the one that allows joining them to the vacuum science for particle accelerators. The vacuum requirements (usually UHV or XHV) in particle accelerators are defined by beam–gas interactions that should be negligible compared to other phenomena that limit the quality of the beam. At such low pressures the main source of gas in the vacuum chamber is a molecular desorption from materials used for the vacuum chamber and its components. The outgassing rates vary over a very wide range and depend on material, cleaning procedure, treatments, temperature, bombardment by particles and accumulated irradiation dose. The gas dynamics is used to design the research facilities to accurately measure and to study outgassing rates at different conditions. By applying these data to the accelerator vacuum design, one would have to consider that outgassing is often non-uniform and changes with time with different functions. The most time-efficient way of beam vacuum optimization is using a 1D diffusion model where all parameters are defined as a function of longitudinal coordinate (along the beam path). A full 3D modelling with TPMC codes provides much more accurate results, however, being time consuming work is not ideal for pumping and design optimization and is used for complex components and for finalized design.