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According to the chemical, carbon isotopic, and hydrogen isotopic compositions and 3 He/ 4 He ratios of 127 natural gas samples, the natural gas in the Tarim Basin is mainly composed of gaseous alkanes dominated by methane. The contents of the gaseous alkanes decrease with the increase of their carbon numbers. The δ 13 C values of CH 4 , C 2 H 6 and C 3 H 8 in the platform area of the Tarim Basin vary in the range of −54.4‰∼-24.4‰ (an average value of −39.2‰), −43.1‰∼-26.7‰ (an average value of −36.1‰) and −37.9‰∼-21.6‰ (an average value of −31.8‰), respectively. The overall carbon isotopic composition of the alkanes follows the trend of δ 13 C 1 < δ 13 C 2 < δ 13 C 3 < δ 13 C 4 and in some cases varies with δ 13 C 1 >δ 13 C 2 or δ 13 C 3 > δ 13 C 4 . The lower carbon isotope values of methane (δ 13 C 1 < δ 13 C 2 ) may be attributed to thermal sulfate reduction (TSR), and the higher propane value (δ 13 C 3 > δ 13 C 4 ) was caused by the mixing of the natural gases of the same genetic type formed at different stages. The methane hydrogen isotopes (δ 2 H-C 1 ) of the natural gases in the Tarim Basin are in the range of −195‰∼-122‰ with an average value of −156‰. The 3 He/ 4 He ratios of the natural gases are in the range of 2.3 × 10 −8 ∼66.8 × 10 −8 , suggesting that there is no deep mantle-derived gas in the platform area of the Tarim Basin. The carbon isotope fractionation of alkane gases (δ 13 C 2 <−28‰ and δ 13 C 3 <−25‰) indicates that the natural gas in the platform area of the Tarim Basin is oil-type. The modified plots of lnC 1 /C 2 vs. lnC 2 /C 3 and C 2 /C 3 vs. δ 13 C 2 -δ 13 C 3 of the natural gases indicate that the oil-type gas in the Tarim Basin has different predominant formation processes, including kerogen-cracking, oil-cracking, oil- and gas-cracking, secondary gas-cracking and mixing of the kerogen-cracking and oil-cracking gases. The gas evolved from gas-cracking gas, to oil- and gas-cracking gas and oil-cracking gas along the direction from the west side of the Manjar Sag to the central Tarim Basin. The natural gases in some areas of Tazhong are the mixtures of the kerogen-cracking and oil-cracking gases. [ABSTRACT FROM AUTHOR]

In this paper, we proposed an alternative way to estimate volumetric vapour: liquid ratio of gaseous or light-petroleum inclusions without fluorescence using regularly-shaped inclusions to estimate volumetric vapour: liquid ratios through geometric methods. The method was applied to the inclusions from the rock samples of the Lower Triassic Feixianguan and Jialingjiang Formations, NE Sichuan (China). The trapping pressures of inclusion fluids were calculated by integrating PVT simulation software, volumetric liquid: vapour ratios determined by the proposed method and homogenization temperatures measured by microthermometry. Fluid densities and gas-oil ratios (GOR) were also estimated. The estimated trapping pressures and temperatures are slightly lower for the Jialingjiang formation (29.69–31.33 MPa, 93.5–105.2 °C) than for the Feixianguan Formation (31.02–34.38 MPa, 98–148 °C), and the trapping time of the inclusions in the Jialingjiang Formation and Feixianguan Formation were estimated at about 173–170 Ma and 178-168 Ma, respectively. The distribution of high pressures correlates with the presence of pyro-bitumen in the reservoir rocks, suggesting the migrated fluid is derived mainly from the secondary cracking of oil. The modeled fluid density and GOR correspond to a typical light oil or condensate, suggesting an origin for the trapped hydrocarbons as an intermediate product in this process. [ABSTRACT FROM AUTHOR]

Based on the thermal simulation experiments of shale and crude oil samples, the amount of gas generated from kerogen and oil cracking during each geological period was calculated based on the chemical kinetic method. The results showed that the total amount of gas generated from the Niutitang Shale in Hy1 well is 49.00 m3/t, including gas generated from kerogen (17.76 m3/t) and gas generated from oil cracking (31.24 m3/t). The period of gas generated from kerogen is from the Cambrian to the Carboniferous with amount of gas generated value of 14.77 m3/t, which is mainly from the Lower Ordovician to the Middle Ordovician (510–470 Ma). The period of gas generated from oil cracking is from the Ordovician to the Triassic, and the main period of gas generated from oil cracking is from the Lower Devonian to the Upper Permian (410–250 Ma). The amounts of gas generated from oil cracking are 13.30 m3/t, 9.44 m3/t, and 3.77 m3/t in the Devonian, Carboniferous, and Permian, respectively. [ABSTRACT FROM AUTHOR]

The Sichuan Basin is a prime gas-producing basin in China. Besides the giant Neoproterozoic Weiyuan gas field discovered in the central paleo-uplift, an extra giant gas reservoir in the Cambrian in this area has been confirmed in recent years. Although the lower Paleozoic in the southwest (Weiyuan area) is normally pressured, it is overpressured in the central area (Moxi-Gaoshiti area). Combined with the seal distribution, five pressure systems, including three overpressure systems, can be divided based on drill-stem test, mud weight, and sonic transit time data. Overpressures appear at depth interval of 1500 to 4900 m (4921 to 16,076 ft), approximately. Benefiting from the good sealing capacity of the gypsum in the Upper and Middle Triassic, high overpressure (pressure coefficient [r] > 2.0) has been preserved in the Lower Triassic, and the Upper Triassic and Cambrian are moderately overpressured (1.3 < r < 1.7). Mechanisms for various overpressure systems are different. Abnormally high sonic transit time in the Permian indicates disequilibrium compaction overpressure. The analyses of sonic transit time-effective stress suggest that disequilibrium compaction is the primary mechanism for the overpressure in the Upper Triassic Xujiahe Formation, but the Cambrian overpressure system is predominantly associated with fluid expansion, which mainly resulted from gas generation. Furthermore, we consider that the late thermal cracking of oil to gas is a key factor for gas and overpressure preservation in old strata. The high overpressure in the Lower Triassic marine carbonate rocks was caused by oil cracking and gypsum dehydration mechanisms. Combining the origin analysis with the burial and hydrocarbon generation histories, we constructed the Cambrian pore pressure evolution model, which is characterized by roughly normal pressure before 200 Ma, overpressuring from 200 to 90 Ma, and overpressure releasing since 90 Ma. [ABSTRACT FROM AUTHOR]

Few previous studies have focused on solid bitumen distribution and its effect on gas reservoir quality during oil cracking. Solid bitumen is commonly found in both gas and nongas reservoirs of the Triassic Feixianguan Formation (T1f) in the Jiannan gas field. The T1f natural gases are mainly secondary cracking gases of oil generated from source rock of the Permian Wujiaping Formation (P2w), and the reservoir experienced temperatures above 150°C (302°F) for about 35 m. y. A relatively narrow range of ln(C1/C2) values and a wide range of ln(C2/C3) values and widespread solid bitumen indicate that oil cracking took place in the gas field. Low concentrations of H2S (commonly <0.81%) suggest that high-reflectance (2.57%-3.07%) solid bitumens are pyrobitumens, which would have been mainly derived from oil cracking. Gases preferentially occupy larger pore spaces, and oil is displaced into small pores and throats by overpressure during oil cracking. In this way, pyrobitumens can reduce the magnitude of porosity in relatively tight reservoirs. Moderate-quality oil reservoirs (paleoporosity 2.2%-8.0%) are between or adjacent to high-quality oil reservoirs and are probably poor-quality or non-gas reservoirs after oil cracking. Carbonate reservoirs (paleoporosity >8.0%) can be high-quality gas reservoirs after oil cracking and should be favorable targets for future gas exploration in the northeastern Sichuan Basin and adjacent areas. [ABSTRACT FROM AUTHOR]

The effects of high pressures on the yield and kinetics of gas generated by the cracking of crude oil were investigated in laboratory simulation experiments. Samples of a low-maturity non-marine oil were recovered from the Paleogene Shahejie Formation in the Dongying depression, Bohai Bay Basin, eastern China. The oils were cracked to gas under different pressure and temperature conditions in an autoclave. Initial temperatures of 300 °C were increased to 650 °C at rates of either 30 or 100 °C/h. Reaction products were analysed at the end of each 50 °C temperature increase. Pressure conditions were either 0.1 MPa (i.e. atmospheric) or 20 MPa. Results show that high pressures inhibit or delay oil-to-gas cracking and retard the initiation of the cracking process. The temperature at which oil was cracked and the activation energy of the formation of C1-5 hydrocarbons increased under high pressure conditions, demonstrating the effects of pressure on the kinetics of the oil-to-gas cracking process. High pressures and high temperatures inhibited the conversion of C2-5 hydrocarbons to methane during secondary cracking. In addition, high pressures retarded the generation of N2, H2 and CO during cracking of oil. The presence of water increased the yields of total cracked gas, C2-5 hydrocarbons and CO2 in high-pressure conditions. The simulation results show that CO2 and C2-5 hydrocarbons have similar yields during oil-to-gas cracking. Using the kinetic parameters determined from the laboratory experiments, the yield and production rate of gas generated during the cracking of oil from Member 4 of the Paleogene Shahejie Formation in the Minfeng-Lijin sag (Dongying depression) were calculated. The results indicate that only limited volumes of natural gas in this area were derived from the cracking of oil, and that most of the gas was derived from the thermal decomposition of kerogen. [ABSTRACT FROM AUTHOR]

The paper focuses on investigating the impact of mineral components of Meihekou oil shale on the conversion of organic carbon from the oil shale into shale oil. A number of leaching operations were performed and each product formed in the bioleaching process was analyzed. The analysis showed that the bioleaching technology used is best for oil shale conversion. The yield of shale oil was from 8.3% to 11.2%, and approximately 8.4% of extra shale oil was obtained. During bioleaching a lot of micropores were generated in oil shale, which is favorable to transfer heat from the outside into the inside of the bioleached oil shale sample. Therefore, more shale oil could be obtained through the micropores rapidly, which may avoid shale oil from cracking into shale gas. Finally, bioleaching contributes to the production of more shale oil. [ABSTRACT FROM AUTHOR]

• Thermally stable ethanodiamondoids discovered in deeply buried marine oils. • Formation process of ethanodiamondoids investigated by thermal simulation. • Ethanodiamondoid-derived proxies established for oil maturity and cracking. • Abundance and isomerization of ethanodiamondoids changes during thermal evolution. • Phase type determined using concentrations of diamondoids and ethanodiamondoids. Diamondoids are often enriched in highly mature oil due to their high resistance to thermal stress. Ethanodiamondoids have similarly high thermal stability. We have detected ethanodiamondoids from 75 oil samples from deep marine carbonate strata in the Tarim Basin, China. Based on thermal simulation experiments on source rock and oil samples, we propose that ethanodiamondoids are gradually created with increasing thermal evolution and oil cracking. Their formation is likely due to free radical reactions of diamondoids with ethane or ethene formed from the cracking of alkanes. A proxy is proposed for the rapid determination of the degree of oil cracking and the petroleum phase based on the relationship between types and concentrations of ethanodiamondoids and diamondoids. [ABSTRACT FROM AUTHOR]

Fluid catalytic cracking (FCC) is a dominant refining conversion process in China's most refineries. After decades of development, China has already become one of the major FCC technology licensors in the world. In this review, the research and development (R&D) activities on FCC riser termination device (RTD) technologies in China are reviewed and discussed. Emphasis is put on the R&D of a series of advanced RTD technologies led by China University of Petroleum, Beijing, which initiated in the early 1990s when more and more China's FCC units chose to process more residue feedstock. Followed by the guideline of three "quick"s and two "high"s, two early types of RTD systems with coupled zones for gas-solids centrifugal separation and pre-stripping were developed and applied successfully in commercial units. Significantly reduced yields of coke and dry gas due to restrained post-riser reactions and satisfactory particle recovery efficiency were achieved. These were the fender-stripper cyclone and vortex quick separator systems designed for external- and internal-riser FCC units, respectively. Later, further improvement efforts led to the development of another two RTD systems, i.e. the circulating-stripper cyclone system for external-riser units and super vortex quick separator system for internal-riser units. By now, nearly 50 applications were commissioned with a sum FCC capacity of 40.0 Mton/a, nearly one-third of China's total FCC processing capacity. Besides, other research efforts, such as the geometry optimization efforts on LD² type separator, the studies on RTD for down-flow riser FCC units, and the idea of non-disengager FCC unit are also discussed in this review. To accommodate to degraded feedstock, more stringent environmental regulations and new FCC process technologies, future R&D efforts on RTD technologies should be put on improvements to further satisfy the three-"quick"s and two-"high"s requirements with changing FCC operating conditions and different process requirements. [ABSTRACT FROM AUTHOR]

Abstract: Although oil cracking has been documented as one of the important sources of gas in many overmature marine sedimentary basins, the chemical and carbon isotopic signatures of gases of this origin are still open to question. In this study a Cambrian crude oil from the central Tarim basin, along with its main separated fractions (saturates, aromatics and asphaltenes), were pyrolyzed in sealed gold tubes to investigate how generated gases vary in chemical and carbon isotopic composition and how this variation would influence the genetic interpretation of oil cracking gas. The results indicate that the gases from cracking of aromatics and asphaltenes are much drier and more enriched in 13C than the gases from the cracking of saturates and crude oil at the same level of thermal maturity. In the experimental run of 20°C/h, the dryness index of the gases (defined as the volume percentage of C1 in C1–5) from the cracking of saturates ranges from 26.2–90.6% with the methane carbon isotope change ranging from −54.8‰ to −35.5‰, whereas the dryness index is never lower than 60.6% for the gases from the cracking of aromatics with methane carbon isotope ranging from −39.9‰ to −32.2‰. Correspondingly, experimental data for the four samples plot in different areas in diagrams designed to distinguish oil cracking gas from kerogen cracking gas, such as ln(C2/C3) vs. δ 13C2–δ 13C3 and δ 13C1 vs. δ 13C2–δ 13C3, indicating compositional variability of crude oil could assert an important influence in these diagrams. Therefore it is prudent to bring other geological constraints into consideration to avoid misinterpretation. The kinetic parameters for the bulk generation of C1–5 gas and the methane carbon isotope fractionation extrapolated to geological conditions of 2°C/Ma and an initial temperature of 50°C show that the temperatures of C1–5 gas generation from the aromatics and asphaltenes are lower than those from the saturates and crude oil due to their lower activation energies and frequency factors. Generation of C1–5 gases from the aromatics is modeled to be initiated about 122°C whereas the initiation temperature for the saturates sample is 176°C. Below 189°C (EasyRo=1.8%), the yields of C1–5 gases follow the order: aromatics>asphaltenes>crude oil>saturates. At similar thermal maturity levels, the methane carbon isotopic compositions are significantly different for the four samples, with an order of 13C enrichment: aromatics>asphaltenes>crude oil>saturates, however the difference in methane carbon isotopes becomes smaller with increasing temperature. This indicates that methane carbon isotopic values can be significantly different for gases cracked from oils that are compositionally diverse, especially in the early stage of methane generation. [Copyright &y& Elsevier]

Deep-seated cracked gas exploration was achieved great breakthrough in Es of the Minfeng area on the northern slope of the Dongying Sag. Carbon isotopic and molecular compositions studies revealed the characteristics of wet gas and a normal trend of carbon isotopic composition. Empirical cutoff points of δC and δC and light hydrocarbon compositions distinguished the cracking gas as sapropelic gas. Variations in i/ nC, i/ nC and δC further confirmed that the gas was cracked from residual kerogen. Source characteristics indicated that the gas was derived from mature-highly mature source rocks of Es with kerogen type II being dominant mixed with some oil-cracking gas. Burial history modeling indicated that there were two hydrocarbon charging periods in Es reservoirs. The first period refers to the Guantao-Minghuazhen stage dominated by oil charging, while the second period refers to the Minghuazhen stage and has been dominated by cracked gas charging till now. [ABSTRACT FROM AUTHOR]

Based on the geochemical characteristics of oil-cracking gas and kerogen-cracking gas revealed by simulation experiments and the chemical composition of natural gases in actual gas reservoirs, two kinds of natural gases with different relationships between C/C and C/C, C/C and C/C, C/C and 100×C/(C-C) were identified in the Tarim Basin, and proposed further by the authors. The relationship charts of C/C and C/C, C/C and C/C, C/C and 100×C/(C-C) can be used to effectively distinguish oil-cracking gas from kerogen-cracking gas. Petroleum geological analysis of the oil-cracking gas reservoirs showed that the distribution of oil-cracking gas is mostly related with deep-seated faults or faults with a large fault throw, and the burial depth of paleo-oil reservoir is relatively high; crude oil-cracking gas resources have been evaluated by using both forward and inversion methods. The plots of C/C vs. C/C, C/C vs. C/C, and C/C vs. 100×C/(C-C) were used to distinguish between oil-cracking gas and kerogen-cracking gas, and estimate the mixed ratios of the two kinds of natural gases in the main gas reservoirs of the platform area. [ABSTRACT FROM AUTHOR]

Abstract: Based on quantitative modeling and experimental data on n-tetracosane cracking to generate gaseous hydrocarbons in a confined system, we calculated the generation kinetics and carbon isotope kinetics of methane, ethane and propane and determined the main controlling factors influencing the variation of δ 13C2 and δ 13C3. The carbon isotope of gaseous hydrocarbons from n-C24 cracking to gas are comparable to those from crude oil reported recently, and they can be used to investigate the geochemical characteristics of crude oil cracking to gas under geological conditions. The geological model of n-C24 cracking suggests it is stable at 150–160°C and its cracking temperature ranges from 180 to 200°C, consistent with geological models of crude oil cracking currently reported. With increasing degree of thermal stress, the changes in δ 13C2 and δ 13C3 are larger than that of δ 13C1. It is shown that isotope accumulation controlled by the recharging history of a reservoir has a considerable impact on the carbon isotope distribution of natural gas. Compared to that of cumulative gas, the carbon isotope ratio of partly accumulation gas is heavier and influences the fractionation of the δ 13C2 and δ 13C3 curves to a greater extent. The geological model of n-C24 cracking to gas has been used to interpret the origin of carbon isotopic variation of natural gas in some reservoirs in the Tarim Basin. [Copyright &y& Elsevier]

The Puguang gas field is the largest gas field found in marine carbonates in China. Marine carbonate reservoirs in this field were buried to a depth of about 7000 m (22,966 ft) and experienced maximum temperature up to 220°C before uplift to the present-day depth of 5000-5500 m (16,404-18,045 ft), with present-day thermal maturity between 2.0 and 3.0% equivalent vitrinite reflectance (Ro). Sulfur-rich pyrobitumens with reflectance up to 3.5% are widespread in the reservoirs and resulted from thermal cracking of crude oils most likely generated from Upper Permian source rocks and thermochemical sulfate reduction (TSR). Natural gases in the Puguang gas field have wide variations in nonhydrocarbon gas contents, with H2S contents between 5.1 and 58.3% and CO2 contents between 7.9 and 18.0%. The hydrocarbon gases originated mainly from thermal cracking of accumulated oil but were altered by TSR. Thermochemical sulfate reduction in the study area exerted different effects on the isotope compositions of different hydrocarbon gas components at different TSR stages. The differential increase of δ13C values for different gas components reflects transformation from a heavy-hydrocarbon-gas--dominated TSR stage to a methane-dominated TSR stage. This caused a decrease of δ13 Cmethane δ13Cethane values and a corresponding conversion from reversed to normal isotope distributions. Thermochemical sulfate reduction in the study area appears to have been limited by sulfate concentrations in the reservoirs. A successive, three-stage TSR series, namely, liquid-hydrocarbon--involved TSR, heavy-hydrocarbongas--dominated TSR, and methane-dominated TSR, occurred in reservoirs with sufficient sulfate concentration. Methane can be the dominant organic reactant for TSR, but only at elevated temperature and after most C2+ hydrocarbons are exhausted. [ABSTRACT FROM AUTHOR]

In recent years several H2S-rich oolite giant gas pools have been discovered in the Lower Triassic Feixianguan Formation of the northeastern Sichuan basin, and their explored gas reserves have been over 5000x108 m³. However, gas sources remain unsolved due to multiple source horizons with high maturity in this area and TSR alterations. By integrating analytical data of natural gas samples with comprehensive investigations on many factors, such as oil-gas geology, distribution and evolution of source rocks, charging and adjustment of gas pools, mixture of natural gases and secondary alterations, the present study concluded that the dominant source for the Feixianguan Fr. gas pools is the Permian Longtan Fr. source rock and secondly the Silurian Longmaxi Fr. source rock. Natural gases from the various gas pools differ genetically due to the matching diversity of seal configurations with phases of hydrocarbon generation and expulsion by different source rocks, among which natural gases in Puguang Gasfield are dominated by the trapped gas generated from the Longtan Fr. source rock and commingled with the gas cracked from the Silurian crude oil, while those in Dukouhe, Tieshangpo and Luojiazhai Gasfields are composed mainly of the Silurian oil-cracking gas and commingled with the natural gas derived from the Longtan Fr. source rock. [ABSTRACT FROM AUTHOR]

Hetianhe gas field, Lungudong gas field and Tazhong gas field are marine marine-origin natural gas reservoirs in the craton area in the Tarim Basin. The natural gas is generated from Cambrian source rocks. The simulation experiment indicated that the cracking of the dispersedly dissoluble organic matter remaining in the source rocks is the main origin of marine natural gas. There are two modes to form gas reservoirs, one is the dry gas reservoir such as Hetianhe gas field, in which gas accumulated on the fault belt with violent tectonic movement, the other is condensate gas reservoir formed on the inheriting uplift such as Lunnan and Tazhong gas fields. The hybrid simulation experiment of cracking gas and crude oil indicated that crude oil accumulated on a large scale in those uplift belts at the early stage, and natural gas filled the ancient oil reservoir at the late stage, and the gas reservoirs were formed after the gas mixed with the crude oil. [ABSTRACT FROM AUTHOR]

The crack state in the regenerator of the heavy oil catalytic cracking unit of Daqing Petrochemical Complex is summarized. The reasons for a large number of welding seam cracks in the regenerator-third-stage cyclone system of the heavy oil catalytic cracking unit are analysed. Correlated countermeasures to prevent cracks and several repair plans for the present cracks are proposed. The key technology and measures of repairs are described and could be used as guides for crack repair of similar equipment. [ABSTRACT FROM AUTHOR]

• Stromatolites and thrombolites constitute major proportion of ancient Ediacaran gas reservoirs. • Buildup of early reservoir spaces was dominated by cavities in microbialite framework and karst vugs. • Petroleum charge and pyrobitumen coat were beneficial for porosity preservation in later burial. • Acidic fluid conditions related to presence of H 2 S and CO 2 linked to petroleum crack and TSR prevent cementation. The ancient Ediacaran Dengying Formation consists of microbialites with unusually high porosity that represent a large proportion of the Weiyuan-Anyue gas reservoirs in southwestern China's Sichuan Basin. However, a clear model for the development and preservation of these microbialite reservoirs has yet not been determined. We used samples from outcrops and borehole cores to characterize these microbialites and propose a model for early development and subsequent reservation of their porosity. Primary porosity in the microbialite framework was mainly represented by fenestrate vugs and elongated cavities between microbial layers that were formed during initial sedimentation as well as secondary karst vugs and caves formed by meteoric karst resulting from subsequent tectonic uplift; these features represent the early development of the microbialite reservoirs. Subsequent filling of vugs by early-stage radial dolomite (RD) and late-stage saddle dolomite (SD) occurred during the deep burial stage, with δ18O and homogenization temperature patterns suggesting continuous cementation. However, most vugs were not cemented due to combination of (1) a rigid dolomitized framework, (2) a closed burial system restricting the flow of mineralized fluid, (3) the presence of petroleum or pyrobitumen, and (4) acidic fluid conditions related to high concentrations of H 2 S and CO 2. The third and fourth factors were linked to presence of hydrocarbons and had made big contribution to porosity retention during deep burial diagenetic stage. [ABSTRACT FROM AUTHOR]