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1
Al-Ameri, Thamer K., Amer Jassim Al-Khafaji, and John Zumberge. "Petroleum system analysis of the Mishrif reservoir in the Ratawi, Zubair, North and South Rumaila oil fields, southern Iraq." GeoArabia 14, no. 4 (October 1, 2009): 91–108. http://dx.doi.org/10.2113/geoarabia140491.
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ABSTRACT Five oil samples reservoired in the Cretaceous Mishrif Formation from the Ratawi, Zubair, Rumaila North and Rumaila South fields have been analysed using Gas Chromatography – Mass Spectroscopy (GC-MS). In addition, fifteen core samples from the Mishrif Formation and 81 core samples from the Lower Cretaceous and Upper Jurassic have been subjected to source rock analysis and palynological and petrographic description. These observations have been integrated with electric wireline log response. The reservoirs of the Mishrif Formation show measured porosities up to 28% and the oils are interpreted as being sourced from: (1) Type II carbonate rocks interbedded with shales and deposited in a reducing marine environment with low salinity based on biomarkers and isotopic analysis; (2) Upper Jurassic to Lower Cretaceous age based on sterane ratios, analysis of isoprenoids and isotopes, and biomarkers, and (3) Thermally mature source rocks, based on the biomarker analysis. The geochemical analysis suggests that the Mishrif oils may have been sourced from the Upper Jurassic Najma or Sargelu formations or the Lower Cretaceous Sulaiy Formation. Visual kerogen assessment and source rock analysis show the Sulaiy Formation to be a good quality source rock with high total organic carbon (up to 8 wt% TOC) and rich in amorphogen. The Lower Cretaceous source rocks were deposited in a suboxic-anoxic basin and show good hydrogen indices. They are buried at depths in excess of 5,000 m and are likely to have charged Mishrif reservoirs during the Miocene. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching the vuggy, highly permeable reservoirs of the Mishrif Formation. Structural traps in the Mishrif Formation reservoir are likely to have formed in the Late Cretaceous.
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Hao, Hui Zhi, and Li Juan Tan. "The Characteristic of Oil and Gas Accumulation and Main Factors of Reservoir Enrichment in SZ36-1 Region." Applied Mechanics and Materials 737 (March 2015): 859–62. http://dx.doi.org/10.4028/www.scientific.net/amm.737.859.
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The hydrocarbon reservoirs which have been found in SZ36-1 region are located in Liaoxi low uplift and dominated by structural traps. The principle source rock is the first and the third member of the Neogen Shahejie Formation and the main reservoir type is delta sand body which mainly located in the second member of Shahejie Formation. Oil reservoirs are mostly in normal pressure and are possess characteristic of late hydrocarbon accumulation. Hydrocarbon accumulation is mainly controlled by fault,reservoir-cap rock combination, and petroleum migration pathways. Lateral distribution of hydrocarbon reservoirs is mostly controlled by reservoir rocks, while the vertical distribution is controlled by fault.
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Tang, Youjun, Meijun Li, Qiuge Zhu, Daxiang He, Xingchao Jiang, Hong Xiao, Junfeng Shan, Wujiang Kang, Junying Leng, and Wenqiang Wang. "Geochemical characteristics and origin of hydrocarbons in the Mesoproterozoic reservoirs in the Liaoxi Depression, NE China." Energy Exploration & Exploitation 38, no. 2 (July 12, 2019): 333–47. http://dx.doi.org/10.1177/0144598719862922.
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Oil reservoirs have been discovered in the Mesoproterozoic strata in the Liaoxi Depression, NE China. In order to determine the source of oil shows of the Mesoproterozoic Gaoyuzhuang Formation and their organic geochemical characteristics, eight source rocks and reservoir cores from the Mesoproterozoic Gaoyuzhuang Formation and four source rocks from the overlying Middle Jurassic Haifanggou Formation were geochemically analysed. The distribution patterns of normal alkanes, acyclic isoprenoids, hopanes, steranes and triaromatic steroids of the Mesoproterozoic hydrocarbons from Well N-1 are consistent with those of source rock extracts from the Mesoproterozoic Gaoyuzhuang Formation in the Well L-1. The molecular marker compositions of source rock extracts from the overlying Middle Jurassic Haifanggou Formation are distinctively different from those of the Mesoproterozoic hydrocarbons. The results suggest that the Mesoproterozoic source rocks have significant petroleum generation potential. The Mesoproterozoic paleo-reservoir may be prospecting exploration targets in the Liaoxi Depression, NE China.
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Peng, Biao, Lulu Zhang, Jianfeng Li, Tiantian Chang, and Zheng Zhang. "Multi-Type Hydrocarbon Accumulation Mechanism in the Hari Sag, Yingen Ejinaqi Basin, China." Energies 15, no. 11 (May 27, 2022): 3968. http://dx.doi.org/10.3390/en15113968.
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With the successful development of unconventional hydrocarbons, the production of unconventional hydrocarbons has increased rapidly. However, a single conventional or unconventional model is not suitable for the mechanism of hydrocarbon accumulation in a given basin or sag. Based on data from drilling, logging, and geophysical analysis, the hydrocarbon accumulation mechanism in the Hari sag in the Yingen-Ejinaqi basin, China, was analyzed. There are three sets of source rocks in the Hari sag: the K1y source rocks were evaluated as having excellent source rock potential with low thermal maturity and kerogen Type I-II1; the K1b2 source rocks were evaluated as having good source rock potential with mature to highly mature stages and kerogen Type II1-II2; and the K1b1 source rocks were evaluated as having moderate source rock potential with mature to highly mature stages and kerogen Type II1-II2. Reservoir types were found to be conventional sand reservoirs, unconventional carbonate-shale reservoirs, and volcanic rock reservoirs. There were two sets of fault-lithologic traps in the Hari sag, which conform to the intra-source continuous hydrocarbon accumulation model and the approaching-source discontinuous hydrocarbon accumulation model. The conclusions of this research provide guidance for exploring multi-type reservoirs and multi-type hydrocarbon accumulation models.
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Guram N., Gordadze, Giruts Maxim V., Poshibaeva Aleksandra R., Postnikova Olga V., Poshibaev Vladimir V., Antipova Olga A., Rudakovskaya Svetlana Yu., Koshelev Vladimir N., and Martynov Viktor G. "Carbonate Reservoir as a Source Rock." Journal of Siberian Federal University. Chemistry 11, no. 4 (December 2018): 575–92. http://dx.doi.org/10.17516/1998-2836-0101.
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Ma, Feng, Wei Yang, Yongshu Zhang, Hongzhe Li, Mei Xie, Xiujian Sun, Pu Wang, and Yadong Bai. "Characterization of the reservoir-caprock of the large basement reservoir in the Dongping field, Qaidam Basin, China." Energy Exploration & Exploitation 36, no. 6 (April 26, 2018): 1498–518. http://dx.doi.org/10.1177/0144598718772317.
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The basement gas reservoir in the Dongping field in the Qaidam Basin is a large reservoir that is different from other basement reservoirs around the world. The basement reservoir does not contain thick mudstone with abundant organic matter that acts as both a source rock and a caprock. The natural gas came from lateral Jurassic source rocks. The basement lithologies in wellblocks Dp3, Dp1, and Dp17 are granite, granitic gneiss, and limestone with slate, respectively, but they all provide effective reservoir space for gas accumulation. The average porosities are 3.3%, 5.2%, and 3.6%, respectively, and the average permeabilities are 0.66 mD, 0.60 mD, and 0.57 mD, respectively. Tectonic fractures are the main factor for improving the physical properties of the reservoir, and secondary solution space is the key factor for the high and stable gas production in the study area. The E1 + 2 Formation, which contains abundant anhydrite, unconformably overlies the basement rock. Some of the anhydrite was deposited as cement and filled the fractures and pores, which led to decreased porosity and to the formation of a tight caprock with a high breaking pressure for hydrocarbon accumulation. The caprock becomes thinner from the lowland to the uplift, and it is missing in wellblock Dp3, which led to the heterogeneous distribution of gas. Anhydrite-bearing caprock is the dominant factor that controls the gas accumulation in the basement rock reservoir in the Dongping field. Studying the spatial distribution of the anhydrite-bearing caprock is important to the exploration and development of basement gas reservoirs in the Qaidam Basin. This unique gas accumulation mechanism in a basement rock reservoir may inspire new ideas for exploring basement oil and gas reservoirs around the world.
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Bian, Baoli, Ablimit Iming, Tianze Gao, Hailei Liu, Wenlong Jiang, Xueyong Wang, and Xiujian Ding. "Petroleum Geology and Exploration of Deep-Seated Volcanic Condensate Gas Reservoir around the Penyijingxi Sag in the Junggar Basin." Processes 10, no. 11 (November 17, 2022): 2430. http://dx.doi.org/10.3390/pr10112430.
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Many types of volcanic rock oil and gas reservoirs have been found in China, showing great petroleum exploration potential. Volcanic reservoir also is one of the key fields of exploration in the Junggar Basin and mainly concentrated in the middle and shallow layers, while the deep volcanic rock and natural gas fields have not been broken through. Based on comprehensive analysis of core observation, single well analysis, reservoir description, source rocks evaluation, combined with seismic data and time-frequency electromagnetic technology, multiple volcanic rock exploration targets were identified, and industrial oil and gas flow was obtained in the well SX 16 of the Penyijingxi Sag, western Junggar Basin. It is believed that the deep Permian source rocks have relatively higher natural gas generation potential and volcanic breccia usually have large reservoir space. And the mudstone of the Upper Wuerhe Formation played as the role of caprock. The success of exploration well SX16 has achieved a major breakthrough in natural gas exploration in the Penyijingxi Sag, which has essential guiding significance for the exploration of deep volcanic rocks and large-scale gas exploration in the Junggar Basin.
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Guo, Qiang, Da Kang Zhong, Yu Lin Wang, and Yan Chun Zhong. "Characteristics of Petroleum Geology and Prediction of Favorable Areas in Jiufotang Formation, Kazuo Basin." Advanced Materials Research 361-363 (October 2011): 3–7. http://dx.doi.org/10.4028/www.scientific.net/amr.361-363.3.
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Through the research on actual measurement 106km geological profile, the hydrocarbon source rocks mainly develop the third member of Jiufotang formation, followed by the second member. There are five distribution areas where have been divided hydrocarbon source rocks thickness is more than 400m in study area. Among them, Jiufotang area has the greatest sedimentary thickness of hydrocarbon source rocks, while Siguanyingzi-Sanjiazi area has the largest area where hydrocarbon source rocks are more than 400m. Oil shale is good hydrocarbon source rock, while dark gray and black gray mudstone (or shale) are relatively poor. The fan delta front subaqueous distributary channel and mouth bar are well-developed in basin’s fault zone and also the important favorable reservoir, followed by braided delta front mouth bar, subaqueous distributary channel and distal bar developing in northwestern area of the basin. There are four forms of source-reservoir-cap combination: (1) hydrocarbon source rock in the above layer and reservoir in the below layer; (2) hydrocarbon source rock and reservoir in the same layer; (3) normal form; (4) fingerlike intersection. The combination of fingerlike intersection is the most important forms in study area. Fan delta facies next to lacustrine facies is favorable exploration area.
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Li, Xiaoshan, Hong Pan, Yuxiao Wu, Guanxing Luo, Junqiang Song, Liu Yang, Kaifang Gu, et al. "Main Control Factors and Hydrocarbon Accumulation Model of Volcanic Oil Reservoirs with Complex Oil–Water Relationships: A Case Study of the Carboniferous in the Chepaizi Uplift, the Junggar Basin, China." Minerals 12, no. 11 (October 26, 2022): 1357. http://dx.doi.org/10.3390/min12111357.
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In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.
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WANG, WEIMING, ZHIXUAN WANG, XUAN CHEN, FEI LONG, SHUANGFANG LU, GUOHONG LIU, WEICHAO TIAN, and YUE SU. "FRACTAL NATURE OF POROSITY IN VOLCANIC TIGHT RESERVOIRS OF THE SANTANGHU BASIN AND ITS RELATIONSHIP TO PORE FORMATION PROCESSES." Fractals 26, no. 02 (April 2018): 1840007. http://dx.doi.org/10.1142/s0218348x18400078.
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In this paper, in a case study of Santanghu Basin in China, the morphological characteristics and size distribution of nanoscale pores in the volcanic rocks of the Haerjiawu Formation were investigated using the results of low temperature nitrogen adsorption experiments. This research showed that within the target layer, a large number of nanoscale, eroded pores showed an “ink bottle” morphology with narrow pore mouths and wide bodies. The fractal dimension of pores increases gradually with increasing depth. Moreover, as fractal dimension increases, BET-specific surface area gradually increases, average pore diameter decreases and total pore volume gradually increases. The deeper burial of the Haerjiawu volcanic rocks in the Santanghu Basin leads to more intense erosion by organic acids derived from the basin’s source rocks. Furthermore, the internal surface roughness of these corrosion pores results in poor connectivity. As stated above, the corrosion process is directly related to the organic acids generated by the source rock of the interbedded volcanic rocks. The deeper the reservoir, the more the organic acids being released from the source rock. However, due to the fact that the Haerjiawu volcanic rocks are tight reservoirs and have complicated pore-throat systems, while organic acids dissolve unstable minerals such as feldspars which improve the effective reservoir space; the dissolution of feldspars results in the formation of new minerals, which cannot be expelled from the tight reservoirs. They are instead precipitated in the fine pore throats, thereby reducing pore connectivity, while enhancing reservoir micro-preservation conditions.
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Kamruzzaman, Asm, Manika Prasad, and Stephen Sonnenberg. "Petrophysical rock typing in unconventional shale plays: The Niobrara Formation case study." Interpretation 7, no. 4 (November 1, 2019): SJ7—SJ22. http://dx.doi.org/10.1190/int-2018-0231.1.
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Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low-porosity and low-permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara Shale in the Denver Basin of the United States: the Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality and a higher source-rock potential. The Upper Chalks and the Marls should have major economic potential. The Lower Chalk has higher porosity and a higher fraction of micro- and nanopores; however, it exhibits poor source-rock potential. The measured core data indicate large mineralogy, organic richness, and porosity heterogeneities throughout the Niobrara interval at all scales.
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Zhang, Lei, Lunwei Zhu, Jianian Shen, and Qifei Huang. "A Three-Fold Classification of Tight Gas Based Primarily on Dynamic Relationship Between Gas Charging History and Reservoir Tightening Process and its Application." Open Petroleum Engineering Journal 8, no. 1 (March 12, 2015): 51–57. http://dx.doi.org/10.2174/1874834101508010051.
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Building upon the foundation of the prior investigations, a three-fold classification of tight gas reservoirs is proposed in this paper which is based primarily on dynamic relationship between gas charging history and reservoir tightening process, coupled with tectonic evolution, source-reservoir relationship, migration and charging pattern. The three categories of tight gas are: (1) “pre-existing” basin-centered gas reservoir, in which the reservoir sands experienced earlystage tightening processes, occurring before peak gas generation, expulsion from source rock, and charging of reservoir; (2) “pre-existing subsequent-improved” tight gas reservoir, in which the reservoir sands were also tightened before gas charging and then underwent reservoirs improvement mainly caused by the tectonic activities; and (3) “subsequentconventional” tight gas reservoir where reserved sands were tightened after the peak of gas generation, expulsion from source rock, and charging of reservoir. This type of tight gas initially formed conventional gas accumulation during gas charging of reservoir, and subsequently modified to tight gas reservoir. All the three categories of tight gas have different geological conditions of gas accumulation and gas accumulation patterns, which can be used as characteristics to classify these tight gas systems, and thus have distinctive control on regional gas distribution. The results of applying this tight gas classification for an actual basin show that correctly distinguishing these three kinds of tight gas reservoirs from each other could contribute greatly to the exploration and development of tight gas reservoirs.
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Abdullah, Fowzia H., Bernard Carpentier, Isabelle Kowalewski, Frans van Buchem, and Alain-Yves Huc. "Organic matter identification in source and reservoir carbonate in the Lower Cretaceous Mauddud Formation in Kuwait." GeoArabia 10, no. 4 (October 1, 2005): 17–34. http://dx.doi.org/10.2113/geoarabia100417.
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ABSTRACT The purpose of this study is to identify the source rock, reservoirs and nonproductive zones in the Lower Cretaceous Mauddud Formation in Kuwait, using geochemical methods. This formation is one of the major Cretaceous oil reservoirs. It is composed mainly of calcarenitic limestone interbedded with marl and glauconitic sands. Its thickness ranges from almost zero in the south to about 100 m (328 ft) in the north. A total of 99 core samples were collected from six oil fields in Kuwait: Raudhatain, Sabiriyah and Bahra in the north, and from the Burgan, Ahmadi and Magwa in the south. Well logs from these fields (gamma ray GR, sonic, resistivity, density) were correlated and used in the study. The core samples were screened for the amount and nature of the organic matter by Rock-Eval 6 pyrolysis (RE6) using reservoir mode. A set of samples was selected to study the properties of the organic matter including the soluble and insoluble organic parts. The geochemical characterisation was performed using different methods. After organic solvent extraction of rock samples, the solvent soluble organic matter or bitumen was characterised in terms of saturates, aromatics and heavy compounds (resins and asphaltenes). Then the hydrocarbon distribution of saturates was studied using gas chromatography (GC/FID) and gas chromatography-mass spectrometry (GC/MS) for tentative oil-source rock correlation. After mineral matrix destruction of previously extracted rocks, insoluble organic matter or kerogen was analysed for its elemental composition to identify kerogen type. The geology and the analytical results show similarities between the wells in the southern fields and the wells in the northern fields. Average Total Organic Matter (TOC) in the carbonate facies is 2.5 wt.% and the highest values (8.0 wt.%) are in the northern fields. The clastic intervals in the northern fields show higher total organic matter (1.3 wt.%) relative to the southern fields (0.6 wt.%). The total Production Index is higher in the carbonate (0.6) than the clastic section (0.3). This reflects the amount of extractable hydrocarbons, which are usually associated with the carbonate section in this formation, representing its reservoir section. Although the carbonate rocks are dominated by richer total organic matter, there are some intervals, with low total organic matter values (0.07 wt.%), representing its poor reservoir sections. The kerogen type varies between type II-III and III in the shales with a slightly better quality in the carbonate section. It is immature in almost all the studied fields. The composition of the rock extract has no relation with the rock type. Some sandstone show similar extract composition to the carbonate rocks in the reservoir intervals. The extracts from these intervals show different genetic nature than those in the shales. The maturity level in the reservoir extract is much higher than in the shale intervals. Thus, the oil accumulated in the reservoir might be largely related to migrated oil from a more mature source rock deposited in a clearly different environment than the associated shaly intervals. The best candidates being a more deeply buried Early Cretaceous Sulaiy Formation and Upper Jurassic Najmah Formation.
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Wang, Qianru, Haiping Huang, Chuan He, and Zongxing Li. "Differential Thermal Evolution between Oil and Source Rocks in the Carboniferous Shale Reservoir of the Qaidam Basin, NW China." Energies 14, no. 21 (October 29, 2021): 7088. http://dx.doi.org/10.3390/en14217088.
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Shale oil and source rock samples of the Carboniferous Keluke Formation from well Chaiye 2 in the Delingha Depression were analyzed by gas chromatography–mass spectrometry. Source rocks were highly mature at the gas generation stage with vitrinite reflectance (Ro) of 1.45–1.88%. However, the oil produced from the shale reservoir was characterized by abundant biomarkers but low abundance of diamondoid hydrocarbons with estimated Ro of ca. 0.78%, indicating hydrocarbons were still at a relatively low thermal maturity level. As the crude oil was generated and accumulated autochthonously, preliminary results indicate that crude oil and source rocks witnessed differential thermal evolution and significant disparity of the current thermal maturity in the shale reservoir due to rapid tectonic subsidence and clay mineral catalysts that accelerated the thermal maturation process. Although tectonic uplifts occurred afterwards, the vitrinite recorded the highest maturity that source rocks have ever reached, whereas the oil has not reached the same maturity level due to less impact from thermal alteration or mineral catalysis than source rocks in the shale reservoir. Such a discovery enlarges the hydrocarbon perseveration of maturity ranges in reservoirs, particularly for the unconventional tight formation, and benefits potential hydrocarbon exploration from highly mature sediments.
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Chen, Junqing, Xiongqi Pang, and Zhenxue Jiang. "Controlling factors and genesis of hydrocarbons with complex phase state in the Upper Ordovician of the Tazhong Area, Tarim Basin, China." Canadian Journal of Earth Sciences 52, no. 10 (October 2015): 880–92. http://dx.doi.org/10.1139/cjes-2014-0209.
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Seven hydrocarbon reservoirs have been discovered to date in the Upper Ordovician of the Tazhong Area, a region in which hydrocarbon phase distribution is complex. In the present study, the genesis and controlling factors of the hydrocarbons with complex phase in the Tazhong Area were investigated on the basis of the geological and geochemical conditions required for the formation and distribution of hydrocarbon reservoirs, integrated with the source rock geochemistry, natural gas and oil properties, and oil and gas reservoir fluid tests PVT (i.e., pressure, volume, and temperature tests). The results indicate that hydrocarbon reservoir types in the Upper Ordovician of the Tazhong Area transition from unsaturated to saturated condensate-gas reservoirs from west to east and from condensate-gas reservoirs to unsaturated-oil reservoirs from north to south. The crude oil in the region originated primarily from the mixing of Lower–Middle Cambrian and Middle–Upper Ordovician source rocks, while the natural gas was sourced primarily from the cracking gas of Lower–Middle Cambrian crude oil. This hydrocarbon-phase distribution was controlled primarily by temperature and pressure and has been affected by multiple periods of hydrocarbon accumulation and alteration. The high-quality Lower–Middle Cambrian reservoir–cap assemblage may be an important target for future exploration of natural gas in the Tazhong Area.
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Sparks, R. S. J., C. Annen, J. D. Blundy, K. V. Cashman, A. C. Rust, and M. D. Jackson. "Formation and dynamics of magma reservoirs." Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences 377, no. 2139 (January 7, 2019): 20180019. http://dx.doi.org/10.1098/rsta.2018.0019.
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The emerging concept of a magma reservoir is one in which regions containing melt extend from the source of magma generation to the surface. The reservoir may contain regions of very low fraction intergranular melt, partially molten rock (mush) and melt lenses (or magma chambers) containing high melt fraction eruptible magma, as well as pockets of exsolved magmatic fluids. The various parts of the system may be separated by a sub-solidus rock or be connected and continuous. Magma reservoirs and their wall rocks span a vast array of rheological properties, covering as much as 25 orders of magnitude from high viscosity, sub-solidus crustal rocks to magmatic fluids. Time scales of processes within magma reservoirs range from very slow melt and fluid segregation within mush and magma chambers and deformation of surrounding host rocks to very rapid development of magma and fluid instability, transport and eruption. Developing a comprehensive model of these systems is a grand challenge that will require close collaboration between modellers, geophysicists, geochemists, geologists, volcanologists and petrologists. This article is part of the Theo Murphy meeting issue ‘Magma reservoir architecture and dynamics’.
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Liang, Mugui, Guang Fu, Xu Han, and Qiaoqiao Li. "Mapping of oil-source faults in reservoir–cap rock combinations without a source rock." Energy Geoscience 3, no. 2 (April 2022): 103–10. http://dx.doi.org/10.1016/j.engeos.2021.11.007.
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Li, Yangbing, Weiqiang Hu, Xin Chen, Litao Ma, Cheng Liu, and Duo Wang. "Study on Geochemical Characteristics of tight sandstone gas accumulation in Linxing area." E3S Web of Conferences 206 (2020): 01017. http://dx.doi.org/10.1051/e3sconf/202020601017.
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Based on the comprehensive analysis of the characteristics of tight sandstone gas composition, carbon isotope, light hydrocarbons and source rocks in Linxing area of Ordos Basin, the reservoir-forming model of tight sandstone gas in this area is discussed. The study shows that methane is the main component of tight sandstone gas, with low contents of heavy hydrocarbons and non-hydrocarbons, mainly belonging to dry gas in the Upper Paleozoic in Linxing area. The values of δ13C1, δ13C2 and δ13C3 of natural gas are in the ranges of -45.6‰ ~ -32.9‰, -28.9‰ ~ -22.3‰ and -26.2‰~ -19.1‰, respectively. The carbon isotopic values of alkane gas show a general trend of positive carbon sequence. δ13C1 value is less than -30‰, with typical characteristics of organic genesis. There is a certain similarity in the composition characteristics of light hydrocarbons. The C7 series show the advantage of methylhexane, while the C5-7 series mainly shows the advantage of isoalkane. The tight sandstone gas in this area is mainly composed of mature coal-derived gas, containing a small amount of coal-derived gas and oil-type gas mixture. According to the mode of hydrocarbon generation, diffusion and migration of source rocks in Linxing area, the tight sandstone gas in the study area can be divided into three types of reservoir-forming assemblages: the upper reservoir type of the far-source type (upper Shihezi formation-shiqianfeng formation sandstone reservoir-forming away from source rocks), the upper reservoir type of the near-source type ( the Lower Shihezi formation sandstone reservoir-outside the source rock), and the self-storage type of the source type (Shanxi formation-Taiyuan formation source rock internal sand reservoir).
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Li, Yong, Shijia Chen, Wen Qiu, Kaiming Su, and Bingyan Wu. "Controlling factors for the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation, Guang’an Area, Sichuan Basin." Energy Exploration & Exploitation 37, no. 1 (October 10, 2018): 26–43. http://dx.doi.org/10.1177/0144598718803224.
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Tight sandstone gas characterized by a wide distribution, local enrichment and a complex gas–water distribution has high exploration potential. This study, using the Xujiahe Formation in the Guang’an gas field as an example, aims to determine the main controlling factors of the enrichment of tight gas through comprehensive analyses of the source rock and reservoir characteristics, pressure evolution and structural effects by using various methods including well logging, geochemistry, mercury injection, reservoir physical properties and formation pressure. The results show that the proximal-source, interbedded hydrocarbon accumulation results from a dispersed hydrocarbon supply, which is the root cause of the widely distributed tight sandstone gas. The abnormally high reservoir pressure caused the enrichment of tight sandstone gas even under insufficient hydrocarbon generation dynamics; in addition, natural gas preferentially accumulated in the relatively high-quality reservoirs under the same hydrocarbon supply, which means that differences in the reservoir physical properties control gas charge in the reservoir. Structure controls the gas–water differentiation under the stable tectonic background, and the higher the structure is, the more abundant the gas–water differentiation is, and the easier pure gas reservoirs form. Therefore, the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation is controlled by source rocks, abnormally high reservoir pressure and the physical properties and structure of the reservoir.
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Hu, Yu Zhao, Pei Rong Zhao, and Yu Hui Lv. "The Petroleum System of Northern Kashi Sag in Tarim Basin and Exploration Direction." Advanced Materials Research 524-527 (May 2012): 89–95. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.89.
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Northern Kashi Sag is located on the northwestern periphery of Tarim Basin, China. This block has been explored for a half century, and Akmomu gas reservoir was discovered in 2001. In Northern Kashi Sag, organic-rich intervals mainly occur in Carboniferous, Lower Permian and Jurassic. Lower Cretaceous Kezilesu Formation(K1kz) is dominated by braid river succession and is best in big thickness of 385-862m，high porosity of 14.90% and high permeability of 207.00 ×10-3μm2. The first grade cap rocks are gypsolyte and mud-gypsolyte in upper Cretaceous and Paleogene with thickness of 100-200m. Two Petroleum Systems are identified, and one is J2y-N1p, Yangye Formation (J2y) serves as source rock, and Neogene Pakabulake(N1p) as reservoir rock. Another is C1+P1by-K1kz petroleum system, Lower Carboniferous and Lower Permian Biyoulieti Formation( P1by) serve as source rock, and Kezilesu Formation (K1kz) as reservoir rock. J2y-N1p petroleum system contains abundant oil sand resource. In 2001,Akmomu gas reservoir was discovered by AK＃1 in C1+P1by-K1kz petroleum system.
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Zhang, Xue Juan, Shuang Fang Lu, Wei Huang, and Lei Zhang. "Analysis of Tight Gas Reservoir Forming Condition in Gulong-Changjiaweizi Region, Northern Songliao Basin." Advanced Materials Research 652-654 (January 2013): 2478–83. http://dx.doi.org/10.4028/www.scientific.net/amr.652-654.2478.
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This paper makes systematic analysis of geological factors of natural gas accumulation in Denglouku formation of Gulong-Changjiaweizi region, including reservoir characteristics, gas source condition, source-reservoir relationship, structural condition, etc. It turned out that K1d2 in Gulong-Changjiaweizi region is generally typical tight sandstone reservoir with low porosity and permeability due to the poor physical properties. The gas source rock of K1d2 formation has larger gas producing capacity.The relationship between source rock and reservoir shows as interbed interfinger or directly contiguity contact, which is beneficial for large-area gas accumulation. The gas generation area of source rock in this region is always in the center and slow downdip direction of Gulong depression with a smaller dip angle on the adjacent tight sandstone reservoir, where faults are rare. The result of comprehensive analysis shows that K1d2 formation in Nothern Songliao Basin and its neighboring layers could be considered as a favorable target of the tight gas reservoir study in Northern Songliao Basin due to its favorable geological conditions of deep basin tight gas reservoir generation, such as tight reservoir, sufficient gas source, communicating source-reservoir relationship and constant flattened structure.
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Wu, Yi, and Wei Chao Tian. "Analysis of the Accumulation Conditions for Volcanic Gas Reservoirs: A Case from Deep Yingcheng Formation, Southern Part of Songliao Basin." Advanced Materials Research 848 (November 2013): 273–78. http://dx.doi.org/10.4028/www.scientific.net/amr.848.273.
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Volcanic gas reservoir in deep Southern Songliao Basin has became source for incremental oil and reserves. Due to the low degree of exploration, study on the accumulation condition for volcanic gas reservoir is insufficient, to some extent, influencing the effectiveness of exploration. In this paper, the accumulation conditions for volcanic gas reservoir have been analyzed systematically including the source rock conditions, reservoir conditions, sealing conditions, conducting conditions and trap conditions. The study results show that large-scale coal-bearing strata in Shahezi Formation can provide sufficient gas for volcanic gas reservoir: the fracture systems in deep volcanic rocks can communicate with the earlier developed pores, fractures and caves, forming good reservoir and flow space; It contains multiple rock types with good preservation condition, the mudstone in first member of Quan Formation is better regional seal. Mudstone in third and fourth member of Denglouku Formation and Shahezi Formation are favorable local seals, with good seal capability for volcanic rocks gas accumulation in Yingcheng Formation. ontains three types of transporting pathways: permeable formation, unconformity and fault.
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Yu, Ying Hua, Hong Qi Yuan, Xiang Li Zhong, and Xue Qiu. "Hydrocarbon Accumulation Characteristics in Cretaceous System Hailaer Basin." Advanced Materials Research 652-654 (January 2013): 2496–500. http://dx.doi.org/10.4028/www.scientific.net/amr.652-654.2496.
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Based on the sequence stratigraphy principle, reservoir forming elements has been detailed analysis in Cretaceous system of Hailaer basin, by using core, logging and 3-D seismic data. The study shows that the thick mudstone layer in the transgressive systems tract of the super-sequence is good regional source rock .and regional caprock, meanwhile the sandbody developed in transgressive systems tract and highstand systems of the super-sequence become the regional reservoir of depression. The main hydrocarbon migration pathway is uncomformable surface, fault, frame-sandstone, or that the hydrocarbon born in source rock went into the sandstone of sublacustrine fan directly, and then, lithologic reservoirs was formed.
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Taylor, Kevin C., Hisham A. Nasr-El-Din, and Sudhir Mehta. "Anomalous Acid Reaction Rates in Carbonate Reservoir Rocks." SPE Journal 11, no. 04 (December 1, 2006): 488–96. http://dx.doi.org/10.2118/89417-pa.
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Summary It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock. This work is the first to show this assumption to be false in some cases, because of mineral impurities commonly found in these rocks. Trace amounts of clay impurities in limestone reservoir rocks were found to reduce the acid dissolution rate by up to a factor of 25, to make the acid reactivity of these rocks similar to that of fully dolomitized rock. A rotating disk instrument was used to measure dissolution rates of reservoir rock from a deep, dolomitic gas reservoir in Saudi Arabia (275°F, 7,500 psi). More than 60 experiments were made at temperatures of 23 and 85°C and HCl concentration of 1.0 M (3.6 wt%). Eight distinctly different rock types that varied in composition from 0 to 100% dolomite were used in this study. In addition, the mineralogy of each rock disk was examined before and after each rotating disk experiment with an environmental scanning electron microscope (ESEM) using secondary and backscattered electron imaging and energy dispersive X-ray (EDS) spectroscopy. Acid reactivity was correlated with the detailed mineralogy of the reservoir rock. It was also shown that bulk anhydrite in the rock samples was converted to anhydrite fines by the acid at 85°C, a potential source of formation damage. Introduction A study of acid reaction rates and reaction coefficients of a dolomitic reservoir rock was recently reported by Taylor et al. (2004a). In that work, it was found that reaction rates depended on mineralogy and the presence of trace components such as clays. This paper examines in detail the relationship between acid reactivity and mineralogy of a deep, dolomitic gas reservoir rock. An accurate knowledge of acid reaction rates of deep gas reservoirs can contribute to the success of matrix and acid fracture treatments. Many studies of acid stimulation treatments of Formation K, a deep, dolomitic gas reservoir in Saudi Arabia, have been published (Nasr-El-Din et al. 2001, 2002a, 2002b; Bartko et al. 2003). It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock during acidizing treatments. However, much of the reported data were obtained with pure limestones, dolomites, and marbles. These include calcite marble (CaCO3) (Lund et al. 1975; de Rozieres 1994; Frenier and Hill 2002), dolomite marble [CaMg(CO3)2] (Lund et al. 1973; Herman and White 1985), Indiana limestone (Mumallah 1991), St. Maximin and Lavoux limestones (Alkattan et al. 1998), Haute Vallée de l'Aude dolomite (Gautelier et al. 1999), Bellefonte dolomite (Herman and White 1985), San Andres dolomite (Anderson 1991), Kasota dolomite (Anderson 1991), and Khuff dolomite reservoir cores (Nasr-El-Din et al. 2002b). The effects of common acid additives on calcite and dolomite dissolution rates were reported in detail (Frenier and Hill 2002; Taylor et al. (2004b; Al-Mohammed et al. 2006). The effects of impurities such as clays on rock dissolution have not been reported.
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Luo, Yong, Jian Guo Wu, Fang Zeng, Ding Jie Huang, and Ya Dong Bai. "Characteristics of Hydrocarbon Accumulation of Putaohua Reservoir in Xingnan Area of Daqing Placanticline." Advanced Materials Research 962-965 (June 2014): 12–15. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.12.
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Through comprehensive study on the combination of each accumulation of Putaohua Reservoir in Xingnan area of Daqing Placanticline, analyzing the controlling factors of hydrocarbon accumulation, accumulation rule and the corresponding exploration ideas, Enriching and developing the study of non-structural reservoir in slopes and depressions of Daqing Placanticline. The study shows that faults are well-developed, especially oil source faults which were active during the crucial moment of hydrocarbon accumulation, as for connecting source rock and reservoir and poor sealing capacity, they are the main passage for hydrocarbon migration. The relations between oil source faults and reservoir greatly restrict the distribution and scale of reservoirs. Accurate evaluation of the relationship between faults and reservoirs has an important significance which can give a guide to the surrounding exploration of Daqing oilfield and improve the success rate of exploration.
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Cai, Jin Hang. "The Accumulation Rules of Budate Burial Hill Hydrocarbon Reservoir of Suderte Oilfield in Hailar Basin." Applied Mechanics and Materials 733 (February 2015): 140–43. http://dx.doi.org/10.4028/www.scientific.net/amm.733.140.
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Metamorphic rock burial hill reservoir of Beier rift in Hailaer Basin, with large scale reservoir and high output has complex fault system. The fault through going direction roughly is NEE direction, and has wide fault section and lateral quickly changed fault displacement. Metamorphic rock reservoir can be divided into the vertical weathered fracture zone, crack and dissolved pores and caves development belt and tight zone. Accumulation is controlled by hydrocarbon ability of source rock, contacting relationship of source rock and reservoir, oil storage ability of reservoir, and vertical and lateral hydrocarbon migration ability of fault and unconformity surface. And formed top surface weathering crust accumulation pattern which the hydrocarbon migrated laterally along the unconformity surface, and interior reservoir pattern of crack broken zone accumulation which hydrocarbon migrated vertically along fault.
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Li, Ji, Jin Wei Liu, and Sai Liu. "Forecast and Geological Significance of Main Channel in Songliao Basin Binbei Area Fuyu Oil Layer." Advanced Materials Research 753-755 (August 2013): 12–15. http://dx.doi.org/10.4028/www.scientific.net/amr.753-755.12.
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For the limitation of seismic data and the difficulty in the identification of main channel in Binbei area. The patterns and methods of two-dimensional seismic data in identifying the main channel are established. It is supplemented by the electrical characteristics of drilling rock to validate which is channel tracking technology of the three-dimensional spectral decomposition. The prediction of Fuyu reservoir main channel is done. The Binbei area has the characteristics of good inheriting, such as multi-material sources and multi-branch. The channel is mainly relying on northern material sources, and also developed western and northeastern material source. Showing meshes characteristics of aggregation and reradiating. Fuyu reservoir's channel sand reservoir is mainly affected by the control of lithology variation belt, flanking occlusion of river bank. Fault truncated block and the vertical block of initial Pan-mudstone and other factors mainly developed three types of oil and gas reservoirs.
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Abeed, Qusay, Ralf Littke, Frank Strozyk, and Anna K. Uffmann. "The Upper Jurassic–Cretaceous petroleum system of southern Iraq: A 3-D basin modelling study." GeoArabia 18, no. 1 (January 1, 2013): 179–200. http://dx.doi.org/10.2113/geoarabia1801179.
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ABSTRACT A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.
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Gong, Lei, Shuai Gao, Xiaofei Fu, Shumin Chen, Bingyang Lyu, and Jiaqi Yao. "Fracture characteristics and their effects on hydrocarbon migration and accumulation in tight volcanic reservoirs: A case study of the Xujiaweizi fault depression, Songliao Basin, China." Interpretation 5, no. 4 (November 30, 2017): SP57—SP70. http://dx.doi.org/10.1190/int-2016-0227.1.
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The Xujiaweizi fault depression is located in the northern part of the Songliao Basin, China. The Yingcheng Formation of the Xujiaweizi fault depression is a fractured tight volcanic reservoir. Many primary pores exist in the tight volcanic reservoirs of the Yingcheng Formation, but their connectivity is very poor. The degree of development of tectonic fractures determines the reservoir quality and the probability of hydrocarbon accumulation. To elucidate the fracture characteristics and their effects on hydrocarbon migration and accumulation, we analyze the fracture genetic types, characteristics, and controlling factors using data from cores, image logs, and thin sections. Then, we evaluate the matching relationship between tectonic fractures and hydrocarbon migration and accumulation by combining the evolution of the source rocks, analysis of the gas-source fault activity period and evolution of the cap rock sealing ability. We find two types of fractures developed in tight volcanic rocks: primary fractures and secondary fractures. Primary fractures mainly include cooling contraction fractures and cryptoexplosive fractures. Secondary fractures could be further divided into tectonic fractures, dissolution fractures, and weathering fractures. Among them, tectonic fractures are dominant. The distribution of tectonic fractures is controlled by lithology, lithofacies, faults, rock anisotropy, and an unconformity. Tectonic fractures are mainly formed in three phases. The time when the second phase of tectonic fractures formed (the Late Quantou-Qingshankou period) coincided with the peak hydrocarbon generation of the source rocks of the Shahezi Formation. Also at that time, the gas-source faults were active and the cap rock had a good top-seal capacity. Thus, the Late Quantou-Qingshankou period was the main period of natural gas accumulation.
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Koch, Jens-Ole, Andreas Frischbutter, Kjell Øygard, and John Cater. "The 35/9-7 Skarfjell discovery: a genuine stratigraphic trap, NE North Sea, Norway." Geological Society, London, Petroleum Geology Conference series 8, no. 1 (March 17, 2017): 339–54. http://dx.doi.org/10.1144/pgc8.34.
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AbstractThe Skarfjell oil and gas discovery, situated 50 km north of the Troll Field in the NE North Sea, was discovered by well 35/9-7 and was appraised by three additional wells operated by Wintershall, in the period 2012–14.The Skarfjell discovery is an example of a combined structural/stratigraphic trap. The trap formed along the northern edge of a deep WNW–ESE-trending submarine canyon, which was created by Volgian erosion of intra-Heather, Oxfordian-aged sandstones and then infilled with Draupne Formation shales. This mud-filled canyon forms the top and side seal, with the bottom seal provided by Heather shales. The reservoir comprises mid-Oxfordian deep-water turbidites and sediment gravity flows, which formed in response to tectonic hinterland uplift and erosion of the basin margin, 10–20 km to the east.The Skarfjell discovery contains light oil and gas, and may be subdivided into Skarfjell West, in which the main oil reservoir and gas cap have known contacts, and Skarfjell Southeast, which comprises thinner oil and gas reservoirs with slightly lower pressure and unknown hydrocarbon contacts.The Upper Jurassic Draupne and Heather formations are excellent source rocks in the study area. They have generated large volumes of oil and gas reservoired in fields, and discoveries for which the dominant source rock and its maturity have been established by oil to source rock correlation and geochemical biomarker analysis. The Skarfjell fluids were expelled from mid-mature oil source rocks of mixed Heather and Draupne Formation origin.The recoverable resources are estimated at between 9 and 16 million standard cubic metres (Sm3) of recoverable oil and condensate, and 4–6 billion Sm3 of recoverable gas. The Skarfjell discovery is currently in the pre-development phase and is expected to come on stream in 2021.
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Jumiati, Wiwiek, David Maurich, Andi Wibowo, and Indra Nurdiana. "The Development of Non-Conventional Oil and Gas in Indonesia." Journal of Earth Energy Engineering 9, no. 1 (April 19, 2020): 11–16. http://dx.doi.org/10.25299/jeee.2020.4074.
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Oil and gas fuel from unconventional types of reservoirs was the development of alternative sources in addition to oil and gas fuels from conventional type reservoirs that can be obtained to meet domestic needs. The development of unconventional oil and gas reservoirs has developed rapidly outside Indonesia, such as in North America and Canada. One type of unconventional oil and gas reservoir was obtained from shale rock reservoirs. Hydrocarbon shale produced from shale formations, both source from rock and reservoir. This unconventional hydrocarbon has a big potential to be utilized. In this study, an analysis of the development of unconventional oil and gas from Shale Hydrocarbons carried out in Indonesia. This research included the distribution of shale reservoir basins, the number of unconventional shale reservoir resources, factors affecting the development of unconventional oil and gas in shale reservoirs in Indonesia, efforts made by the government to promote exploration activities, exploitation of shale reservoirs in Indonesia, and existing regulations for non-conventional oil and gas. The development of unconventional oil and gas reservoir shale needed to be developed immediately and will attract investors to meet domestic needs for renewable energy needs. From the geological data obtained, there were 6 basins and 11 formations that analyzed for commercialization. Tanjung and Batu Kelau Formation was a prospect formation from 4 desired data categories. In terms of regulation, it still needed improvement to increase the interest of upstream oil and gas entrepreneurs in the unconventional oil and gas shale reservoir. Research in the field of unconventional oil and gas exploitation technology for hydrocarbon shale needed to be improved.
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Shao, Xiaozhou, Yong Li, Miaomiao Wang, Meijuan Chu, Yalin Qi, and Xiaolei Zhang. "Characteristics and Controlling Factors of the Chang 8 Oil Reservoir in the Yanchi Area of the Ordos Basin: A Case Study of Well G20." Geofluids 2022 (February 22, 2022): 1–15. http://dx.doi.org/10.1155/2022/6228834.
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In the Ordos Basin, the Chang 8 oil reservoir of the Triassic Yanchang Formation is the main target of oil exploration and development and there are many factors affecting the hydrocarbon accumulation. Well G20 is an important exploration well in the Yanchi area in the northwestern part of the basin, and the core of the Chang 8 reservoir was sampled and tested to determine the source rocks, trace element composition, mineral composition, reservoir physical properties, and oil-bearing properties. The results show that the rock retrieved exhibits delta plain subfacies; the range of the Chang 8 water body was large, with a gentle slope, and the climate was relatively dry. These findings suggest that this reservoir was deposited in an environment in which sedimentary sand body could easily form. The Chang 8 sandstone reservoir pores are dominated by intergranular pores and feldspar intragranular dissolution pores, indicating that the Chang 8 reservoir is a low-porosity and low-permeability reservoir. Chang 7 source rocks from this area have a type I-II1 hydrocarbon-generating potential, with an average total organic carbon (TOC) content of 5.99% and vitrinite reflectance (Ro) value of 0.48%. Combined with the regional sedimentary evolution, tectonic movement, and reservoir distribution, it is considered that due to the lack of lithologic traps or low-amplitude structural traps, G20 produced water in well testing. The Chang 8 oil reservoir in the Yanchi area can be divided into structural reservoirs and structural-lithologic reservoirs. The conventional oil and gas reservoir exploration ideas of “thick sand belt” and “reservoir sweet spot” are not applicable here. The lithology traps or low-amplitude structural traps and areas with good preservation conditions are the main directions for the next phase of exploration in the northwestern part of the Ordos Basin.
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Woodward, Jack, Jon Minken, Melissa Thompson, Margarita Kongawoin, Laurence Hansen, and Rylan Fabrici. "The Lower Triassic Caley Member: depositional facies, reservoir quality and seismic expression." APPEA Journal 58, no. 2 (2018): 878. http://dx.doi.org/10.1071/aj17172.
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Recent exploration success in the Lower Keraudren Formation of the Bedout sub-basin has resulted in the emergence of the Caley Member reservoirs (Thompson et al. 2018). The interplay of several unique characteristics at this stratigraphic level are favourable for the generation, trapping and deliverability of hydrocarbons. These unique characteristics include, the preservation of porosity and permeability at depths greater than 4000 m, an organic-rich delta-plain lagoon mudstone source rock interbedded with the reservoir and the presence of a thick hemi-pelagic shale. This proximity of the mature source rocks and reservoir quality units combined with a thick overlying shale has created a highly efficient system for trapping hydrocarbons. Seismic data is a key tool to help unlock this play. Seismic imaging of a relatively thin reservoir at a depth below 4000 m has proved challenging. Quadrant has undertaken several stages of reprocessing and conducted multiple seismic inversions to better image and predict the reservoir. Integration and interpretation of geophysical, geological and geochemical data of this recently discovered reservoir has increased Quadrant’s understanding of the potential of the under-explored Bedout sub-basin.
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Yin, Jintao, Chao Gao, Mingjun Zhu, Hui Wang, Peng Shi, Yi yi Chen, Qianping Zhao, Lixia Zhang, and Bo Yu. "Oil Accumulation Model and Its Main Controlling Factors in Lower Yanchang Formation, Wuqi-Dingbianarea, Ordos Basin, China." Geofluids 2021 (May 6, 2021): 1–10. http://dx.doi.org/10.1155/2021/5511563.
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Based on the studies of sedimentary facies, oil-source correlation, formation pressure structure, homogenization temperature of fluid inclusions, etc., the oil and gas accumulation model and main controlling factors in lower Yanchang Formation in Wuqi-Dibian area have been discussed. It is believed that two sets of source rocks, C7 and C9, are developed in study area, and hydrocarbon produced from layers of C8 and C9 is mainly from C7 source rock, followed by C9, according to oil-source correlation; hydrocarbon-generating pressurization of C7 source rock is the main driving force for the downward migration of oil. The high value area formed by the low value of overpressure difference between C7 and C8 is the main hydrocarbon accumulation area; deltaic front subaqueous distributary channel and mouth bar in lower Yanchang formation are the main accumulation spaces due to their good porosity and permeability; besides, C8 reservoir shows the characteristics of “episodic filling and continuous accumulation,” and they both are the undersource reservoir-forming combination; it is believed that the distribution of oil reservoir in Triassic series is controlled by the factors of “near source, low pressure, superior facies.”
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Li, Bin, Qiqi Li, Wenhua Mei, Qingong Zhuo, and Xuesong Lu. "Analysis of accumulation models of Middle Permian in Northwest Sichuan Basin." Earth Sciences Research Journal 24, no. 4 (January 26, 2021): 419–28. http://dx.doi.org/10.15446/esrj.v24n4.91149.
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Great progress has been made in middle Permian exploration in Northwest Sichuan in recent years, but there are still many questions in understanding the hydrocarbon accumulation conditions. Due to the abundance of source rocks and the multi-term tectonic movements in this area, the hydrocarbon accumulation model is relatively complex, which has become the main problem to be solved urgently in oil and gas exploration. Based on the different tectonic backgrounds of the middle Permian in northwest Sichuan Basin, the thrust nappe belt, the hidden front belt, and the depression belt are taken as the research units to comb and compare the geologic conditions of the middle Permian reservoir. The evaluation of source rocks and the comparison of hydrocarbon sources suggest that the middle Permian hydrocarbon mainly comes from the bottom of the lower Cambrian and middle Permian, and the foreland orogeny promoted the thermal evolution of Paleozoic source rocks in northwest Sichuan to high maturity and over maturity stage. Based on a large number of reservoir physical properties data, the middle Permian reservoir has the characteristics of low porosity and low permeability, among which the thrust nappe belt and the hidden front belt have relatively high porosity and relatively developed fractures. The thick mudstone of Longtan formation constitutes the regional caprock in the study area and the preservation condition is good as a whole. However, the thrusting faults destroyed the sealing ability of the caprock in the nappe thrust belt. Typical reservoir profiles revealed that the trap types were different in the study area. The thrust fault traps are mainly developed in the thrust nappe belt, while the fault anticline traps are developed in the hidden front belt, and the structural lithological traps are developed in the depression belt. The different structural belts in northwest Sichuan have different oil and gas accumulation models, this paper built three hydrocarbon accumulation models by the analysis of reservoir formation conditions. The comprehensive analysis supposed the hidden front belt is close to the lower Cambrian source rock, and the reservoir heterogeneity is weak, faults connected source rock is developed, so it is a favorable oil and gas accumulation area in the middle Permian.
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Cui, Junping, Hua Tao, Zhanli Ren, Wei Jin, Hao Liu, Zhangyong Meng, and Kezhang Cheng. "Genesis and Accumulation Period of CO2 Gas Reservoir in Hailar Basin." Energies 15, no. 17 (August 25, 2022): 6183. http://dx.doi.org/10.3390/en15176183.
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Gas reservoirs with high CO2 have been found in several wells in the Hailar Basin. In this paper, a composition analysis, stable carbon isotope analysis, and a rare gas helium isotope 3He/4He and argon isotope 40Ar/36Ar analysis were carried out. These comprehensive analyses show that the CO2 in the Hailar Basin is inorganic-origin gas, which generally has the characteristics of crust–mantle-mixed CO2, and the fraction of helium of mantle source can reach 15.12~18.76%. There are various types of CO2 gas reservoirs. CO2 gas mainly comes from deep crust. The distribution of gas reservoirs is mainly controlled by deep faults and volcanic rocks, as well as by reservoir properties and preservation conditions. Magmatic rocks provide gas source conditions for the formation of inorganic CO2 reservoirs. Deep–large faults provide the main migration channels for CO2 gas. The sandy conglomerate and bedrock weathering crust of the Nantun Formation and the Tongbomiao Formation provide favorable reservoir spaces for the formation of CO2 gas reservoirs. The combination of volcanic rock mass and deep–large faults creates a favorable area for CO2 gas accumulation. The age of magmatic intrusion and the homogenization temperature of oil–gas inclusions in Dawsonite-bearing sandstone indicate that 120 Ma in the Early Cretaceous was the initial gas generation period of the CO2 reservoir and that oil and gas were injected into the reservoir in large quantities in 122~88 Ma. This period is the peak period of magmatic activity in Northeast China, as well as when the crust of Northeast China greatly changed. A large-scale CO2 injection period occurred in 100~80 Ma, slightly later than the large-scale injection period of the oil and gas. Since the Cenozoic, the structure has been reversed, and the gas reservoir has been adjusted.
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Ma, Jian, Zhilong Huang, Xiaoyu Gao, and Changchao Chen. "Oil–source rock correlation for tight oil in tuffaceous reservoirs in the Permian Tiaohu Formation, Santanghu Basin, northwest China." Canadian Journal of Earth Sciences 52, no. 11 (November 2015): 1014–26. http://dx.doi.org/10.1139/cjes-2015-0055.
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Tight oil in the Permian Tiaohu Formation in the Santanghu Basin, northwest China, has a peculiar property such that the reservoir is sedimentary organic matter-bearing tuff characterized by high porosity (10%–25%) and very low permeability, mainly in the range of 0.01–0.50 mD. Biomarker and stable carbon isotope compositions of selected crude oils and source-rock extracts were analyzed to determine the source rock of the tight oil. Source rocks in the Lucaogou Formation consist of various rock types dominated by mudstones containing organic matter with intense yellow–green fluorescence. Mudstones in the Lucaogou Formation have total organic carbon (TOC) values mainly in the range of 1.0–8.0 wt%, hydrocarbon generation potential (S1 + S2) mostly >6 mg/g, and chloroform extractable bitumen “A” generally >0.1%. The maceral composition is predominantly fluorescing amorphinite. The hydrogen index (HI) varies from 300 to 900 mg HC/g TOC, indicating dominant Type I and Type II kerogen. Compared with the mudstones and tuffs in the Tiaohu Formation, the mudstones in the Lucaogou Formation are the best source rocks. The biomarker characteristics of mudstone extracts in the Lucaogou Formation differ from those in the Tiaohu Formation, based on the gammacerane index, β-carotane content, and the relative contents of C27, C28, and C29 regular steranes. Crude oil samples in the tuff show low pristane/phytane (Pr/Ph) ratios, high gammacerane indices, high β-carotane, and a dominance of the C29 regular sterane followed by C28 and C27 steranes, as well as depleted stable carbon isotope compositions. Oil–source correlation with biomarkers and δ13C values shows that the crude oil in the tuffs mainly originates from underlying source rocks in the Lucaogou Formation. The sedimentary organic matter in the tuffs also makes a small contribution to the tuffaceous reservoir. Therefore, the tuffaceous tight reservoir in the Tiaohu Formation is unusual in that the oil is not indigenous; rather, it migrates a long distance to accumulate in the upper reservoir.
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Wang, Yao-Ping, Xin Zhan, Tao Luo, Yuan Gao, Jia Xia, Sibo Wang, and Yan-Rong Zou. "Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea." Energy Exploration & Exploitation 38, no. 6 (August 17, 2020): 2695–710. http://dx.doi.org/10.1177/0144598720950467.
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The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.
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Hao, Yi Wei, and Hai Yan Hu. "Main Controlled Elements for Accumulation of Ultro-Low Permeability Sandstone Oil Reservoir, Zhenjing Oilfield, Ordas Basin." Advanced Materials Research 868 (December 2013): 70–73. http://dx.doi.org/10.4028/www.scientific.net/amr.868.70.
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Ordos Basin is the second largest sedimentary basin in China with very rich oil and gas resources. The exploration targets are typical reservoirs of low permeability. To determine the accumulation mechanism of tight sandstone reservoir, thin section, SEM, numerical calculation were used. The result showed that sandstone should be ultro-low permeability reservoirs with the high content feldspar and lithic arkose or feldspathic litharenite. The reservoir became tight while oil filling, buoyant force is too small to overcome the resistance of capillary force. Therefore, overpressure induced by source rock generation is the accumulation drive force.
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Tanykova, Natalya, Yuliya Petrova, Julia Kostina, Elena Kozlova, Evgenia Leushina, and Mikhail Spasennykh. "Study of Organic Matter of Unconventional Reservoirs by IR Spectroscopy and IR Microscopy." Geosciences 11, no. 7 (June 30, 2021): 277. http://dx.doi.org/10.3390/geosciences11070277.
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The study of organic matter content and composition in source rocks using the methods of organic geochemistry is an important part of unconventional reservoir characterization. The aim of this work was the structural group analysis of organic matter directly in the source rock in combination with a quantitative assessment and surface distribution analysis of the rock sample by FTIR spectroscopy and FTIR microscopy. We have developed new experimental procedures for semi-quantitative assessment of the organic matter content, composition and distribution in the source rocks and applied these procedures for the study of the samples from the Bazhenov shale formation (West Siberia, Russia). The results have been verified using the data from the study of organic matter obtained by Rock-Eval pyrolysis and differential thermal analysis. The obtained results demonstrate the prospects of FTIR spectroscopy and FTIR microscopy application for non-destructive and express analysis of the chemical structure and distribution of organic matter in rocks.
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Wang, Ming Jian, and Xun Hua Zhang. "Lower Paleozoic Hydrocarbon Accumulation Conditions of Middle Uplift in Southern Yellow Sea Basin." Advanced Materials Research 524-527 (May 2012): 1252–55. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1252.
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Guided by the theory of petroleum system, we analyzed the Lower Palaeozoic hydrocarbon accumulation elements and conditions of the Middle uplift of Southern Yellow Sea Basin and concluded the hydrocarbon accumulation pattern. The results showed that: the source rock of lower Palaeozoic in the Middle uplift of Southern Yellow Sea Basin consists of the dark mudstone and carbonate rock; carbonate rock is the main favorable reservoir followed by clastic rock; there are three source-reservoir-cap assemblages; the source rock of Lower Palaeozoic has experienced two hydrocarbon generation stages which are late Silurian and late Middle Triassic; hydrocarbon generated by Lower Palaeozoic source rock can only migrate to the traps near the center of hydrocarbon generation by sandbody and cracks in a short distance; lithologic trap and broad anticlinal trap are the main types in the study area. Through the above analysis, we conclude two accumulation patterns of Lower Palaeozoic in the Middle uplift of Southern Yellow Sea Basin.
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Manshad, Abbas Khaksar, Reza Sedighi Pashaki, Jagar A. Ali, Stefan Iglauer, M. Memariani, Majid Akbari, and Alireza Keshavarz. "Geochemical study of the early cretaceous Fahliyan oil reservoir in the northwest Persian Gulf." Journal of Petroleum Exploration and Production Technology 11, no. 6 (May 14, 2021): 2435–47. http://dx.doi.org/10.1007/s13202-021-01178-2.
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AbstractThree crude oil samples from the Fahliyan Formation in ‘KG’ and ‘F’ fields in the northwest Persian Gulf, namely KG-031, F9A-3H and F15-3H for the geochemical study. In this study, the physicochemical properties, gas chromatography (GC, GC Mass) and (Detailed Hydrocarbon Analysis) DHA analyses for the collected Fahliyan oils were carried out. The API, Trace Element (Ni, V) and S% parameters indicated that the Fahliyan oil was generated from a source rock which deposited in reducing environment condition with a carbonate-shale compound lithology. Moreover, low pour point, higher S% and low viscosity parameters of “KG” sample confirmed the existence of medium oil characteristics in this field. In addition, the geochemical outcomes of GC, GC–MS and DHA analyses indicated that the ‘KG’ oils are more aromatic compared with ‘F’ oil; while biomarkers revealed that Fahliyan reservoir oil is highly mature and was formed from a carbonate source rock containing types II, III kerogen. Thus, sterane/hopane biomarkers (C24/C23 and C22/C21 ratios) revealed that Fahliyan oil originated from carbonate source rocks deposited in an anoxic to dysoxic environment, which is consistent with the above analyses. It was identified that the source rock age is early Cretaceous to late Jurassic. It can be reported that the Fahliyan oils from both fields were generated in the same source rock and have almost the same physical properties, and will have the same production strategy.
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Dong, Yi Si, Xing He Yu, Zhi Hao Yang, Fang Zeng, Ying Li, and Jiao Wang. "Comparison of Qingshankou Formation in Songliao Basin with Bakken Formation in Williston Basin." Advanced Materials Research 962-965 (June 2014): 16–20. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.16.
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Based on geological background, this study is to understand the potential of tight oil of Qingshankou Formation in Songliao Basin by comparing lithofacies features, oil-generating conditions and reservoir characteristics. Hundreds of samples are analyzed to derive geochemical parameters, such as organic richness, kerogen type, and source rock maturity. The results indicate that source rocks of Qingshankou Formation are organic rich, contain oil-prone kerogen, and are thermally mature. The tight reservoir of Qingshankou Formation has complicated pore throat structure, abundant fractures, and an beneficial place for oil accumulation.
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Tiainen, S., H. King, C. Cubitt, E. Karalaus, T. Prater, and B. Willis. "DRILL CUTTINGS ANALYSIS—A NEW APPROACH TO RESERVOIR DESCRIPTION AND CHARACTERISATION; EXAMPLES FROM THE COOPER BASIN, AUSTRALIA." APPEA Journal 42, no. 1 (2002): 495. http://dx.doi.org/10.1071/aj01027.
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In the absence of conventional core data, drill cuttings provide a continuous, independent and relatively inexpensive data source. Data collected from this often under-utilised resource can be used to determine permeability, provide information on diagenesis, stratigraphy and sedimentology, locate natural fractures, discriminate between genuinely poor reservoir and under performing assets and assist with petrophysical characterisation. Data can also be acquired in real time at the wellsite.Drill cuttings analysis or rock typing is a visual method of semi-quantitatively describing rock and pore characteristics from drill cuttings. More specifically it partitions rocks into distinct permeability groups according to their petrophysical properties as observed under high-powered stereo microscope. Based on the observation of key visible attributes, the rocks are assigned to one of six rock types equivalent to the following permeability ranges; 1A (>100mD ambient), 1B (10-100 md ambient), 1C (1-10 mD ambient), 1D (0.5- 1 mD ambient), type II (0.5-0.07 mD ambient) and type III (One of the major strengths of rock typing is it can be used to provide an estimate of in-situ permeabilities. As rock type categories are related to ambient permeability classes an algorithm has been developed to take these ambient range estimates to single in-situ values for permeability and then taking into consideration the lithology in the sample, calculates a permeability height (kh) for the interval. The algorithm corrects for overburden, klinkenberg and relative permeability effects.A comparison of kh derived from rock typing with kh derived from production and test data indicates a strong correlation between the two datasets. Results indicate that the kh sources are consistently similar and fall within one third of an order of magnitude of each other. As both of these data sources are independently derived it suggests both are realistic derivations of the actual kh of the reservoir interval. Consequently, once calibrated to all data sources, rock typing is considered capable of providing a robust estimate of in-situ kh for a specified reservoir interval.
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Bryndzia, L. T., and N. R. Braunsdorf. "From Source Rock to Reservoir: The Evolution of Self-Sourced Unconventional Resource Plays." Elements 10, no. 4 (August 1, 2014): 271–76. http://dx.doi.org/10.2113/gselements.10.4.271.
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Feng, Ziyan, Cheng Feng, Yuntao Zhong, Zhijun Qin, Rui Mao, Lei Zhao, and Xianghua Zong. "TOC estimation of shale oil reservoir by combining nuclear magnetic resonance logging and nuclear physics logging." Journal of Geophysics and Engineering 19, no. 4 (August 2022): 833–45. http://dx.doi.org/10.1093/jge/gxac052.
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Abstract The evaluation of source rock properties has become a vital step in logging interpretation. Total organic carbon (TOC) content is the key to estimating the quality and hydrocarbon generation potential of source rocks. In the shale oilfield of the Junggar Basin, the conventional method of calculating the TOC of hydrocarbon source rocks cannot satisfy logging evaluation requirements. This paper predominantly deals with a method for the quantitative estimation of TOC in source rocks via nuclear physics and nuclear magnetic resonance (NMR) logs. According to this method, the total hydrogen index of the source rock is the sum of the response of kerogen, clay minerals and fluid, expressed by corrected neutron porosity. The hydrogen index of fluid and clay minerals is indicated by the effective porosity of NMR and the estimated clay content, respectively. To eliminate the hydrogen index of fluid, the effective NMR porosity is subtracted from the corrected neutron porosity. On this basis, a new and overlapping method suitable for clay-rich rocks and oil reservoirs is proposed. This method was developed by overlaying the scaled clay content curve on the hydrogen index curve. In non-source rocks, the two curves regularly overlap. However, in organic-rich rocks the two curves will separate. The separation distance between the two curves was used to estimate TOC continuously. Possessing sound application and benefiting from the measured results of sweet spots, this method provides new insights for TOC quantitative prediction in shale oil reservoirs.
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Jiang, Sheng Ling, Chun Lin Zeng, Sheng Xiu Wang, and Mei Li. "Accumulation Conditions of Paleozoic Shale Gas and its Resources in Northeast Chongqing Areas." Advanced Materials Research 868 (December 2013): 186–91. http://dx.doi.org/10.4028/www.scientific.net/amr.868.186.
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In order to carry out a more comprehensive discussion on shale gas accumulation conditions of Lower Cambrian Shuijingtuo Formation and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation, the distribution, source rock conditions and reservoir conditions of these two shales are comprehensively analyzed, these two shales are both have the characteristics of high organic carbon content, high maturity, appropriate thickness and mainly typeⅠkerogen as source rocks, and interbedded with siltstone and/or fine sandstone, rich in quartz and other detrital components, easy to break and form the cracks, micro cracks as reservoirs, these characteristics provide a favorable material basis and reservoir space for shale gas accumulating. On this basis, the effective distribution areas of these two shales are further determined and shale gas resources are preliminary evaluated, eventually come to the results of shale gas resources of Lower Cambrian Shuijingtuo Formation and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation respectively are 0.409×1012m3and 0.389×1012m3.
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Chen, Qinglong, Renhai Pu, Xiaomin Xue, Ming Han, Yanxin Wang, Xin Cheng, and Hanning Wu. "Controlling Effect of Wave-Dominated Delta Sedimentary Facies on Unconventional Reservoirs: A Case Study of Pinghu Tectonic Belt in Xihu Sag, East China Sea Basin." Geofluids 2022 (June 13, 2022): 1–19. http://dx.doi.org/10.1155/2022/8163011.
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In order to find the “sweet spots” of unconventional oil and gas from the Pinghu Formation in the Pinghu Tectonic Belt, we are committed to clarifying the development and distribution rules of coal-measure source rocks and tight reservoirs as well as the controlling factors. Using 3D seismic and logging data, combined with logging constraints of target lithology and pyrolysis experiments of source rock, "source and reservoir" research of uncoventional oil and gas was carried out in the Pinghu Tectonic Belt. The results show that two stages of regression and one stage of transgression occurred in the Pinghu Formation, resulting in river-controlled and wave-controlled delta-neritic facies dominated by sedimentary facies, source rocks developed in interdistributary bay and swamp microfacies, and tight sandstones in point bar and distributary channel microfacies are developed. The accumulation of coalbed methane and shale gas is controlled by the sedimentary facies and the degree of thermal evolution under the factors of burial depth. The accumulation of tight sandstone is closely related to the dominantly sedimentary facies and diagenetic modification of physical properties and faults. It is concluded that the structural type, type and distribution of faults, and depositional environment of the Pinghu Tectonic Belt in the Xihu Sag are the key factors controlling the development and accumulation of coal-measure source rocks and tight sandstone reservoirs. This understanding provides a clear direction for the deep exploration of unconventional oil and gas in the sag and provides a reference for finding reservoir “sweet spots.”
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Christiansen, F. G., and F. Rolle. "Project 'Nordolie': hydrocarbon source rock investigations in central North Greenland." Rapport Grønlands Geologiske Undersøgelse 125 (December 31, 1985): 17–21. http://dx.doi.org/10.34194/rapggu.v125.7882.
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The project 'Nordolie' was initiated under the Danish Ministry of Energy's Research Programme 1983. The aim of the project is to obtain general knowledge about the source rock geology of central North Greenland. Similar investigations have previously been carried out in eastern North Greenland (Rolle, 1981; Rolle & Wrang, 1981). The main purpose of the project is to study the presence and distribution of potential hydrocarbon source rocks in the region and to evaluate the thermal maturity pattern. Studies of reservoir properties, trapping possibilities, and other aspects of petroleum geology will accordingly have a much lower priority.
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Wang, Na, Shuang Fang Lu, and Dian Shi Xiao. "Hydrocarbon Origin and Accumulation Model of Putaohua Reservoir in Southern Daqing Placanticline Area." Advanced Materials Research 616-618 (December 2012): 64–68. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.64.
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There are great oil and gas exploration prospect in south of Daqing Placanticline, with unclear understanding of source rock and accumulation model, the progress of oil exploration is restricted. To definite the source of oil and gas, according to chromatography data and analysis data, combined with potential of hydrocarbon generation and expulsion, oil-gas migration pathway, the hydrocarbon migration and accumulation model is proposed. It can be concluded that the oil from Putaohua reservoir in the south of Daqing Placanticline area mainly come from K2qn1 source rock locally, while the hydrocarbon sources of K2qn1 in the east and west of the depression makes small contribution to the research area. Migrate in source area is the main hydrocarbon migration and accumulation mode. Re-define the oil source of Putaohua reservoir can help enhance the cognition of the hydrocarbon accumulation condition and accumulation model, in order to direct the research for the accumulation and distribution principle of oil and gas exploration and favorable area prediction in the future.