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1
Lü, Xiuxiang, Weiwei Jiao, Xinyuan Zhou, Jianjiao Li, Hongfeng Yu, and Ning Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tazhong Uplift, Tarim Basin, Western China." Energy Exploration & Exploitation 27, no. 2 (April 2009): 69–90. http://dx.doi.org/10.1260/0144-5987.27.2.69.
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Diverse types of marine carbonate reservoirs have been discovered in the Tazhong Uplift, Tarim Basin, and late alteration of such reservoirs is obvious. The marine source rocks of the Cambrian-lower Ordovician and the middle-upper Ordovician provided abundant oil and gas for hydrocarbon accumulation. The hydrocarbons filled various reservoirs in multiple stages to form different types of reservoirs from late Caledonian to early Hercynian, from late Hercynian to early Indosininan and from late Yanshanian to Himalayan. All these events greatly complicated hydrocarbon accumulation. An analysis of the discovered carbonate reservoirs in the Tazhong Uplift indicated that the development of a reservoir was controlled by subaerial weathering and freshwater leaching, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoir beds, the hydrocarbon accumulation zones in the Tazhong area were identified as: karsted reservoirs, reef/bank reservoirs, dolomite interior reservoirs, and hydrothermal reservoirs. Such carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift, respectively. Because of differences in the mechanism of reservoir formation, the reservoir space, capability, type and distribution of reservoirs are often different in different carbonate hydrocarbon accumulation zones.
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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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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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Lerche, Ian. "Hydrocarbon Flow-up Intersecting Faults: Leakage/Production and Bypass Considerations." Energy Exploration & Exploitation 23, no. 4 (August 2005): 225–43. http://dx.doi.org/10.1260/014459805775219157.
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This article considers flow of hydrocarbons up a master fault that bifurcates and allows the hydrocarbons to enter or bypass reservoirs on either side of the bifurcated fault. In addition, leakage (or production) from each reservoir is allowed with a finite time span for the leakage. The rates of leakage from the two reservoirs are also allowed to be different so that the reservoirs either may fill, with concomitant bypass of excess hydrocarbons, or may be drained so rapidly by the leakage that they fill only partially. The timing of the leakage in respect of the timing of hydrocarbon fill is also included so that one can see how the differences in onset and end times of the leakage in relation to end time of the hydrocarbon supply influence the final fill of each reservoir. Uncertainties associated with each of the parameters entering the assessments are also allowed for, so that one can determine which of the uncertain parameters is causing the greatest uncertainty in estimates of the reservoir fill and bypass.
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Ojo, Odunayo Tope. "Petrophysical and Geomechanical Analysis to Delineating Reservoirs in the Miocene Niger Delta Region of Nigeria." Geoinformatica Polonica 22 (December 1, 2023): 105–21. http://dx.doi.org/10.4467/21995923gp.23.009.18608.
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The application of various petrophysical and elastic metrics has advanced reservoir characterization and provided critical geological formation information. Porosity declines with depth, according to sonic, neutron, and density logs. Lithology, pressure, and hydrocarbons all contribute to this. Formation resistivity and fluid saturation are used to identify hydrocarbon-bearing zones. Because oil and gas are non-conductive, hydrocarbon-containing rocks are more resistant than water. In lithological categorization, gamma logs and the Vp/Vs ratio have helped classify reservoirs as Agbada Formation sand-shale reservoirs. Reservoir elastic characteristics, specifically sandstones, have been studied at various depths. These discoveries have an impact on their brittleness, strength, and failure risk in a variety of scenarios. Hydrocarbon accumulation has been influenced by diagenetic compaction equilibrium in pressure-exposed shale source beds. The research advances our understanding of the geological formations of the Niger Delta and gives practical insights for exploration and production. Decisions on oil and gas are based on hydrocarbon reservoir assessments at various depths, including porosity, fluid saturation, and lithology. Well logs from Wells B001, B002, and B003 revealed the diverse properties of several Niger Delta reservoirs. These discoveries have benefited hydrocarbon exploration and production decision-making significantly.
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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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Mujakperuo, B. J. O., and O. J. Airen. "Pressure volume temperature evaluation of Sapele Field, Niger Delta, Southern Nigeria." Environmental Technology and Science Journal 15, no. 1 (June 24, 2024): 168–75. http://dx.doi.org/10.4314/etsj.v15i1.17.
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Sapele field is a large, brown field with complex subsurface structure that has led to heavy compartmentalization of its reservoirs which has also resulted to low reservoir pressure in some parts of the field leading to low production output. Reservoirs were delineated at various depth, some at near surface area (Benin formation) while others at greater depth (Agbada formation), hence the field was further subdivided into two (Sapele Shallow and Sapele Deep) due to its structural complexity. Pressure Volume Temperature (PVT) laboratory analysis on different wells was available for this study and the viscosity of the reservoir fluid was measured using an Electromagnetic Viscometer (EMV) at reservoir temperatures of 129 0F and 207 0F. These data were used in determining hydrocarbon chemical composition, its viscosity, specific gravity, density, and American Petroleum Institute (API) unit. Sapele Shallow reservoir is made up of heavy oil as its hydrocarbon content as a result of biodegradation process in which micro-organisms degrade the light hydrocarbons due to the shallow nature of the reservoir in the field, making it rich in heavy molecular weight hydrocarbon compounds. While Sapele Deep is made up of heavily compartmentalized reservoirs with gas and light oil as its hydrocarbon content. Hence the field requires different exploitation and production approach to fully annex its reservoir hydrocarbon content.
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Rashid, Muhammad, Miao Luo, Umar Ashraf, Wakeel Hussain, Nafees Ali, Nosheen Rahman, Sartaj Hussain, Dmitriy A. Martyushev, Hung Vo Thanh, and Aqsa Anees. "Reservoir Quality Prediction of Gas-Bearing Carbonate Sediments in the Qadirpur Field: Insights from Advanced Machine Learning Approaches of SOM and Cluster Analysis." Minerals 13, no. 1 (December 24, 2022): 29. http://dx.doi.org/10.3390/min13010029.
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The detailed reservoir characterization was examined for the Central Indus Basin (CIB), Pakistan, across Qadirpur Field Eocene rock units. Various petrophysical parameters were analyzed with the integration of various cross-plots, complex water saturation, shale volume, effective porosity, total porosity, hydrocarbon saturation, neutron porosity and sonic concepts, gas effects, and lithology. In total, 8–14% of high effective porosity and 45–62% of hydrocarbon saturation are superbly found in the reservoirs of the Eocene. The Sui Upper Limestone is one of the poorest reservoirs among all these reservoirs. However, this reservoir has few intervals of rich hydrocarbons with highly effective porosity values. The shale volume ranges from 30 to 43%. The reservoir is filled with effective and total porosities along with secondary porosities. Fracture–vuggy, chalky, and intracrystalline reservoirs are the main contributors of porosity. The reservoirs produce hydrocarbon without water and gas-emitting carbonates with an irreducible water saturation rate of 38–55%. In order to evaluate lithotypes, including axial changes in reservoir characterization, self-organizing maps, isoparametersetric maps of the petrophysical parameters, and litho-saturation cross-plots were constructed. Estimating the petrophysical parameters of gas wells and understanding reservoir prospects were both feasible with the methods employed in this study, and could be applied in the Central Indus Basin and anywhere else with comparable basins.
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Zhao, Shuangfeng, Wen Chen, Zhenhong Wang, Ting Li, Hongxing Wei, and Yu Ye. "Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China." Energy Exploration & Exploitation 36, no. 4 (February 22, 2018): 801–19. http://dx.doi.org/10.1177/0144598718759560.
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The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.
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Lerche, Ian. "Hydrocarbon Flow along Intersecting Faults." Energy Exploration & Exploitation 23, no. 2 (April 2005): 107–23. http://dx.doi.org/10.1260/0144598054529996.
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This paper is concerned with the channeling of hydrocarbon flow up a master fault and the diversion of the flow to the left or right at the intersection of the master fault with a second fault. In particular, when reservoirs of different capacities can exist on the master fault and the secondary fault, the question of the retention efficiency of the reservoirs to the hydrocarbon flow is of interest. In addition, given the customary lack of sharp knowledge of the hydrocarbon petroleum system before drilling, the influence of uncertainties in the flow and reservoir properties is discussed in terms of statistical probabilistic representations and the dominant components to the uncertainties of retention and/or bypass are addressed. There is no consideration given in this paper to the possibility of production from the reservoirs before, during, or after fill by the hydrocarbons being supplied along the faults. That problem will be addressed in the next paper.
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Zhou, Tianqi, Chaodong Wu, Xutong Guan, Jialin Wang, Wen Zhu, and Bo Yuan. "Effect of Diagenetic Evolution and Hydrocarbon Charging on the Reservoir-Forming Process of the Jurassic Tight Sandstone in the Southern Junggar Basin, NW China." Energies 14, no. 23 (November 23, 2021): 7832. http://dx.doi.org/10.3390/en14237832.
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Deeply buried sandstones in the Jurassic, Toutunhe Formation, are a crucial exploration target in the Junggar Basin, NW China, whereas, reservoir-forming process of sandstones in the Toutunhe Formation remain unknown. Focused on the tight sandstone of the Toutunhe Formation, the impacts of diagenesis and hydrocarbon charging on sandstone reservoir-forming process were clarified based on the comprehensive analysis of sedimentary characteristics, petrography, petrophysical characteristics, and fluid inclusion analysis. Three diagenetic facies developed in the Toutunhe sandstone reservoirs, including carbonate cemented facies (CCF), matrix-caused tightly compacted facies (MTCF), and weakly diagenetic reformed facies (WDF). Except the WDF, the CCF and the MTCF entered the tight state in 18 Ma and 9 Ma, respectively. There was only one hydrocarbon emplacing event in sandstone reservoir of the Toutunhe Formation, charging in 13 Ma to 8 Ma. Meanwhile, the source rock started to expel hydrocarbons and buoyancy drove the hydrocarbon via the Aika fault belt to migrate into sandstone reservoirs in the Toutunhe Formation. During the end of the Neogene, the paleo-oil reservoir in the Toutunhe Formation was destructed and hydrocarbons migrated to the sandstone reservoirs in the Ziniquanzi Formation; some paleo-oil reservoirs survived in the WDF. The burial pattern and change of reservoir wettability were major controlling factors of the sandstone reservoir-forming process. The buried pattern of the Toutunhe Formation in the western section of the southern Junggar Basin was “slow and shallow burial at early stage and rapid and deep burial at late stage”. Hence, pore capillary pressure was extremely low due to limited diagenetic reformation (average pore capillary pressures were 0.26 MPa). At the same time, high content of chlorite coating increased the lipophilicity of reservoirs. Therefore, hydrocarbons preferably charged into the WDF with low matrix content (average 4.09%), high content of detrital quartz (average 28.75%), high content of chlorite films (average 2.2%), and lower pore capillary pressures (average 0.03 MPa). The above conditions were favorable for oil and gas enrichment.
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Sun, Yu, Shi Zhong Ma, Bai Quan Yan, and Chen Chen. "Controlling Factors for Reservoirs Distribution of the Putaohua Oil Layer in the Saozhao Sag." Advanced Materials Research 616-618 (December 2012): 816–20. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.816.
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Types of found reservoirs and its distribution characteristics of Putaohua oil layer in the Sanzhao Sag were analyzed. The controlling factors of hydrocarbon distribution were investigated. Sanzhao Sag is Sag-wide oil-bearing, but its distribution of oil and water is extremely complicated. The reservoir types are mainly fault block reservoirs, low amplitude structure reservoirs, fault-lithologic reservoirs and lithologic reservoirs. The distribution of reservoirs is mainly controlled by three geological factors: first, long-term inherited nose-like structure is predominant direction of petroleum migration; it induced oil and gas migration at a critical period of hydrocarbon accumulation and formed oil-gas accumulation area. Second, fault across main-line of hydrocarbon migration and high angle skew plug off hydrocarbon, and its side adjacent to Sag is a large number of hydrocarbon accumulation areas. Third, multi-fault region can easily form a fault (-lithological) reservoir accumulation area in the slope of sag.
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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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Shi, Wen-rui, Chong Zhang, Shao-yang Yuan, Yu-long Chen, and Lin-qi Zhu. "A Crossplot for Mud Logging Interpretation of Unconventional Gas Shale Reservoirs and its Application." Open Petroleum Engineering Journal 8, no. 1 (August 19, 2015): 265–71. http://dx.doi.org/10.2174/1874834101508010265.
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The drilling time data of gas logging are used to calculate drilling time ratio of the reservoir, and the total hydrocarbon data are used to calculate hydrocarbon contrast coefficient and to establish the drilling time ratio--hydrocarbon contrast coefficient crossplot. The standards of distinguishing the boundaries of hydrocarbon zones, hydrocarbonaceous water layers and dry layers are determined according to the statistics of regional oil testing data. Based on the standards, the crossplot is divided into three areas: hydrocarbon zone, hydrocarbonaceous water layer and dry layer, which are used in mud logging interpretation of abnormal shows in oil and gas layers. This method is widely used for low-resistivity reservoirs, fracture reservoirs, shale gas layers, and especially in the oil and gas zone with weak show and a single component. It is more applicable and accurate than some conventional interpretation methods such as the triangle plot, PIXLER plot, dual light hydrocarbon alkyl ratio and hydrocarbons ratio (3H).
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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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Chen, Mei Tao, Ning Yang, and Shang Ming Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tahong Uplift Tarim Basin, Western China." Advanced Materials Research 403-408 (November 2011): 1511–16. http://dx.doi.org/10.4028/www.scientific.net/amr.403-408.1511.
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Analyzing the discovered carbonate reservoirs in the Tazhong area, Tarim Basin indicates that the development of a reservoir is controlled by subarial weathering and freshwater leaching processes, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoirs, the hydrocarbon accumulation zones in the Tazhong area are classified into four types: buried hill and palaeoweathering crust, organic buildup reef-bank, dolomite interior, and deep fluid alteration. Different types of carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift. Because of the different mechanisms of forming reservoirs in different carbonate hydrocarbon accumulation zones, the reservoir space, reservoir capability, type of reservoir and distribution of reservoirs are often different.
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Sun, Zhen, Zhen Yang, Xiaoning He, Cixuan Wan, Gang He, Qiang Ren, Shihu Zhao, Wei Cheng, and Sisi Chen. "Geochemical Characteristics of Formation Water in Carbonate Reservoirs and Its Indication to Hydrocarbon Accumulation." Geofluids 2022 (October 11, 2022): 1–11. http://dx.doi.org/10.1155/2022/6095178.
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The migration path of formation water plays an indispensable role in hydrocarbon accumulation and preservation. The hydrodynamic field controls the content of various ions in formation water and is an important participant in hydrocarbon evolution. Formation water can basically be used to judge the preservation status of oil/gas reservoirs, especially for carbonate reservoirs; the carbonate reservoirs are a typical example in the Gaoqiao area of the Ordos Basin, China. However, it is not easy to evaluate the sealing and integrity of the gas reservoir because hydrocarbon has experienced a multistage charging process and complicated later reconstruction. The geochemical characteristics of Ordovician formation water (100 brine samples from 67 wells in the Ma5 Member) are studied, and their chemical composition is analyzed in the Ordos Basin. The results show that formation water has high overall salinity and is the original sedimentary water of the carbonate reservoir, which is the sealing reservoir and can promote the accumulation of hydrocarbons. This is also associated with stronger water-rock reactions and diagenetic transformations, such as dolomitization. The main (TDS) range is from 40 to 150 g·L−1, with an average of 66.16 g·L−1; the Cl− content in the formation water samples is the highest, followed by Ca2+, Na+, Mg2+, HCO3−, and SO42−. In addition, the (Cl−-Na+)/Mg2+ ratio, Na+/Cl− ratio, Mg2+/Ca2+ ratio, and S O 4 2 − × 100 / C l − ratio are closely related to gas preservation. The indication function between chemical parameters of formation water and hydrocarbon dynamics can be better understood in carbonate reservoirs by analogy study, so as to improve the accuracy of discriminating favorable hydrocarbon accumulation areas.
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Neff, Dennis B. "Incremental pay thickness modeling of hydrocarbon reservoirs." GEOPHYSICS 55, no. 5 (May 1990): 556–66. http://dx.doi.org/10.1190/1.1442867.
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The one-dimensional convolution model or synthetic seismogram provides more information about the seismic waveform expression of hydrocarbon reservoirs when petrophysical data (porosity, shale volume, water saturation, etc.) are systematically integrated into the seismogram generation process. Use of this modeling technique, herein called Incremental Pay Thickness (IPT) modeling, has provided valuable insights concerning the seismic response of several offshore Gulf of Mexico amplitude anomalies. Through integration of the petrophysical data, comparisons between seismic waveform response and expected reservoir pay thickness are extended to include estimates of gross pay thickness, net pay thickness, net porosity feet of pay, and hydrocarbons in place. These 1-D synthetic data easily convert to 2-D displays that often show exceptional waveform correlations between the synthetic and actual seismic data. Anomalous observed waveform responses include complex tuning curves; diagnostic isochron measurements even in unresolved thin-bed reservoirs; and extreme variations in the seismic expression of hydro-carbon-fluid contacts. While IPT modeling examples illustrate both the variability and nonuniqueness of seismic responses to hydrocarbon reservoirs, they often show good seismic predictability of pay thickness if the appropriate choice of amplitude-isochron versus pay thickness is made (i.e., peak amplitude, trough amplitude, or average amplitude versus gross pay thickness, net pay thickness, net porosity feet of pay, or hydrocarbons in place).
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Zagranovskaya, D. E., S. I. Isaeva, A. P. Vilesov, V. A. Shashel, O. A. Zakharova, E. O. Belyakov, V. Yu Demin, I. L. Kudin, and G. A. Kalmykov. "Structure of continues reservoirs in the Domanik formation and petrophysical interpretation methods." Moscow University Bulletin. Series 4. Geology 1, no. 6 (January 29, 2022): 120–32. http://dx.doi.org/10.33623/0579-9406-2021-6-120-132.
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Properties of unconventional prospective deposits are interconnected by the rocesses of reservoir formation and oil and gas formation. Dispersed dolomite in situ formed during the maturation of TOC from syngenetic magnesium in the rock matrix increases the void space of the rock, thereby forming an unconventional reservoir filled with autochthonous hydrocarbons and oil components. In the process of TOC maturation and hydrocarbon migration, the TOC components are redistributed in the void space, thereby, the released volume of rocks is filled with stationary resinous asphaltene substances, which sharply reduces the reservoir properties of unconventional reservoirs. As a result, the definition of “organic” porosity includes a broader concept than just the porosity of kerogen. This is a more complex physicochemical process of transformation of the organic matter itself and the redistribution of elements within the formation as a result of the maturation of TOC components and hydrocarbon migration. When assessing the oil and gas potential in the section, we distinguish three groups of rocks: unconventional reservoirs with an increased TOC content and the presence of mobile hydrocarbons; bituminous rocks, in which part of the pore volume is filled with resinous-asphaltene substances and host dense carbonate rocks without organic matter. Also, sporadically developed traditional reservoirs are distinguished throughout the section of the Domanik type of rocks.
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Ziemelis, Karl. "Hydrocarbon reservoirs." Nature 426, no. 6964 (November 2003): 317. http://dx.doi.org/10.1038/426317a.
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Zhang, Yuanyuan, Zhanli Ren, Youlu Jiang, and Jingdong Liu. "Differential hydrocarbon enrichment in deep Paleogene tight sandstones of the Dongpu Depression in Eastern China." Energy Exploration & Exploitation 39, no. 3 (January 21, 2021): 797–814. http://dx.doi.org/10.1177/0144598720988112.
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To clarify the characteristics and enrichment rules of Paleogene tight sandstone reservoirs inside the rifted-basin of Eastern China, the third member of Shahejie Formation (abbreviated as Es3) in Wendong area of Dongpu Depression is selected as the research object. It not only clarified the geochemical characteristics of oil and natural gas in the Es3 of Wendong area through testing and analysis of crude oil biomarkers, natural gas components and carbon isotopes, etc.; but also compared and explained the types and geneses of oil and gas reservoirs in slope zone and sub-sag zone by matching relationship between the porosity evolution of tight reservoirs and the charging process of hydrocarbons. Significant differences have been found between the properties and the enrichment rules of hydrocarbon reservoirs in different structural areas in Wendong area. The study shows that the Paleogene hydrocarbon resources are quasi-continuous distribution in Wendong area. The late kerogen pyrolysis gas, light crude oil, medium crude oil, oil-cracked gas and the early kerogen pyrolysis gas are distributed in a semicircle successively, from the center of sub-sag zone to the uplift belt, that is the result of two discontinuous hydrocarbon charging. Among them, the slope zone is dominated by early conventional filling of oil-gas mixture (at the late deposition period of Dongying Formation, about 31–27 Ma ago), while the reservoirs are gradually densified in the late stage without large-scale hydrocarbon charging (since the deposition stage of Minghuazhen Formation, about 6–0 Ma). In contrast, the sub-sag zone is lack of oil reservoirs, but a lot of late kerogen pyrolysis gas reservoirs are enriched, and the reservoir densification and hydrocarbon filling occur in both early and late stages.
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Fu, Siyi, Zhiwei Liao, Anqing Chen, and Hongde Chen. "Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China." Energy Exploration & Exploitation 38, no. 2 (August 19, 2019): 348–71. http://dx.doi.org/10.1177/0144598719870257.
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The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.
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Finecountry, S. C. P., and S. Inichinbia. "Lithology and Fluid discrimination of Sody field of the Nigerian Delta." Journal of Applied Sciences and Environmental Management 24, no. 8 (September 9, 2020): 1321–27. http://dx.doi.org/10.4314/jasem.v24i8.3.
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The lithology and fluid discrimination of an onshore Sody field, of the Niger Delta was studied using gamma ray, resistivity and density logs from three wells in the field in order to evaluate the field’s reservoir properties. Two reservoir sands (RES 1 and RES 2) were delineated and identified as hydrocarbon bearing reservoirs. The petrophysical parameters calculated include total porosity, water saturation and volume of shale. The results obtained revealed that the average porosity of the reservoir sands, range from 21% to 39%, which is excellent indicator of a good quality reservoir and probably reflecting well sorted coarse grain sandstone reservoirs with minimal cementation. Water saturation is low in all the reservoirs, ranging from 2% to 32%, indicating that the proportion of void spaces occupied by water is low, and implying high hydrocarbon saturation. The crossplot discriminated the reservoirs lithologies as sand, shaly sand and shale sequences, except well Sody 2 which differentiated its lithologies as sand and shale sequences and distinguished the reservoirs’ litho-fluids into three, namely; gas, oil and brine. These results suggest that the reservoirs sand units of Sody field contain significant accumulations of hydrocarbon.
Keywords: Reservoir, porosity, net-to-gross, impedance, lithology
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Liu, Shaojun, Shengxian Zhao, Xuefeng Yang, Jian Zhang, Meixuan Yin, Qi’an Meng, Bo Li, and Ziqiang Xia. "“Tri-in-One” Accumulation Model of Lithologic Reservoirs in Continental Downfaulted Basins: A Case Study of the Lithologic Reservoir of Nantun Formation in Tanan Sag, Mongolia." Processes 11, no. 8 (August 4, 2023): 2352. http://dx.doi.org/10.3390/pr11082352.
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This article analyzes the key controlling factors and hydrocarbon distribution rules of lithologic reservoirs in a continental downfaulted basin according to the structural features, sedimentary evolution, types of sedimentary facies, source rock features, diagenesis evolution, reservoir features, hydrocarbon formation mechanisms, exploration status, and hydrocarbon resource potential. The results show that three major controlling factors (sandbody types, effective source rocks, and effective reservoirs) and one coupled factor (fractures that act as a tie) influence hydrocarbon accumulation in the lithologic traps in the Nantun Formation in Tanan Sag. With the increase in depth, sufficient hydrocarbon is generated in the source rock with thermal evolution. When the depth threshold is reached and critical conditions of hydrocarbon supply are met, hydrocarbon generation and expulsion are more intensive. Traps that are surrounded or contacted by source rock or connected by faults are able to form reservoirs. As the buried depth increases, the intensity of hydrocarbon generation–expulsion grows, and the trap is more petroliferous. Hydrocarbon accumulation and reservoir formation are also controlled by sandbody accumulation conditions. When the critical conditions for hydrocarbon generation are met and concrete oil and gas are charged in, the better physical properties of the sandbody will always indicate more hydrocarbon accumulation in the trap. The allocation of sand type, effective source rock, and an effective reservoir is optimized under the effect of fractures and the coupled hydrocarbon reservoir with these three elements.
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Islamov, Shamil, Ravil Islamov, Grigory Shelukhov, Anar Sharifov, Radel Sultanbekov, Rustem Ismakov, Akhtyam Agliullin, and Radmir Ganiev. "Fluid-Loss Control Technology: From Laboratory to Well Field." Processes 12, no. 1 (January 2, 2024): 114. http://dx.doi.org/10.3390/pr12010114.
Full textAbstract:
Effective fluid-loss control in oil wells is a critical concern for the oil industry, particularly given the substantial reserves situated in carbonate reservoirs globally. The prevalence of such reservoirs is expected to rise with the slow depletion of hydrocarbons, intensifying the need to address challenges related to deteriorating reservoir properties post well-killing operations. This deterioration results in significant annual losses in hydrocarbon production at major oil enterprises, impacting key performance indicators. To tackle this issue, this study focuses on enhancing well-killing technology efficiency in carbonate reservoirs with abnormally low formation pressures. To address this issue, the authors propose the development of new blocking compositions that prevent the fluid loss of treatment fluids by the productive reservoir. The research tasks include a comprehensive analysis of global experience in well-killing technology; the development of blocking compositions; an investigation of their physico-chemical, rheological, and filtration properties; and an evaluation of their effectiveness in complicated conditions. The technology’s application in the oil and gas condensate fields of the Volga-Ural province showcases its practical implementation. This study provides valuable insights and solutions for improved fluid-loss control in carbonate reservoirs, ultimately enhancing well performance and hydrocarbon recovery.
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D., Imikanasua, Tamunobereton-Ari I, and Ngeri A.P. "Determination of Reservoir Quality in Field “D” in Central Niger Delta, Using Well Log Data." Asian Journal of Applied Science and Technology 06, no. 01 (2022): 142–51. http://dx.doi.org/10.38177/ajast.2022.6117.
Full textAbstract:
Well log data was used in this study to assess reservoir properties of field "D" in the southern area of the Niger Delta. For successful petrophysical evaluation, three hydrocarbon-bearing reservoirs (reservoirs A, B, and C) were identified and correlated. The following metrics were tested to determine reservoir properties: porosity, permeability, shale volume, fluid saturation, and net pay thickness. The calculated reservoir property values indicate high reservoir quality. Porosity readings in well OTIG 2 are almost the same, averaging 20%, but values in wells OTIG 7 and OTIG 9 vary from 14-20%. The reservoirs' average permeability was greater than 100md. However, in wells OTIG 2 and OTIG 9, values steadily decline with depth due to compaction caused by the overburden pressure of the underlying rock. Hydrocarbon saturation values in well OTIG 2 are almost the same, averaging 60%, but vary from 60-70% in well OTIG 7 as well as 48-55% in well OTIG 9. Water saturation values in well OTIG 2 are almost the same, averaging 40%, but range from 30-40% in well OTIG 7 and 45-52% in well OTIG 9. The average bulk volume water values in well OTIG 2 are almost the same, averaging 8%, but range from 6-8% in well OTIG 7 and 7-9% in well OTIG 9. There is some evidence that reservoirs A, B, and C in well OTIG 2 are one continuous sand body. This is due to the fact that their porosity, bulk volume water, hydrocarbon saturation, and water saturation values are all roughly the same, and their depth values are all quite similar. The bulk volume water values support the hypothesis that these formations are homogeneous and near irreducible water saturation. The reservoirs found in the field contain hydrocarbons.
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Junira, Adi, and Andy Setyo Wibowo. "SHALE AS HYDROCARBON RESERVOIRS." Scientific Contributions Oil and Gas 39, no. 2 (October 8, 2018): 71–75. http://dx.doi.org/10.29017/scog.39.2.104.
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Nowadays, shale plays a role as hydrocarbon producing rock. Due to its unusual properties as a reservoir, shale is classified as an unconventional reservoir. Among these properties are the relatively low permeability (0.1 mD or less) and the relatively low porosity (10% or less). The relatively low permeability had been the main obstacle to extracting the hydrocarbon held by shale in the past. Nevertheless, the technologies of horizontal drilling and hydraulic fracturing have proven to be effective in stimulating a liquid flow in low permeability reservoirs such as a shale layer which has encouraged the hydrocarbon exploration in the oil shale industry. This paper is intended to provide an overview of technologies implemented in the current oil shale reservoir along with their challenges summarized from available sources in a concise manner.
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Collen, J. D. "Diagenetic Control of Porosity and Permeability in Pakawau and Kapuni Group Sandstones, Taranaki Basin, New Zealand." Energy Exploration & Exploitation 6, no. 3 (June 1988): 263–80. http://dx.doi.org/10.1177/014459878800600307.
Full textAbstract:
Porosity and permeability of Cretaceous to Oliogocene Pakawau and Kapuni Group sandstones in Taranaki Basin, New Zealand, have been extensively modified by burial diagenesis. Mechanical compaction and the precipitation of silica, carbonate and authigenic clays have caused marked deterioration of potential and actual reservoirs for hydrocarbons. Other authigenic minerals have had less effect. Secondary reservoir porosity and permeability have developed in significant volumes in sandstones at various places, at depths below about 2.5 km. They have formed by dissolution of detrital grains, authigenic cements and authigenic replacement minerals, and by fracturing of rock and grains. The most important process for commercial hydrocarbon accumulation in New Zealand is mesogenetic carbonate (particularly calcite) dissolution. As the most prospective source and reservoir rocks are low in the Cretaceous-Tertiary sequence, the depth of burial necessary for hydrocarbon generation means that most primary porosity has been lost and secondary porosity is essential for a commercial accumulation. Entrapment of hydrocarbons in reservoirs higher in the sequence probably also requires the development of secondary permeability to allow migration.
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Sun, Xiaoming, Siyuan Cao, Xiao Pan, Xiangyang Hou, Hui Gao, and Jiangbo Li. "Characteristics and prediction of weathered volcanic rock reservoirs: A case study of Carboniferous rocks in Zhongguai paleouplift of Junggar Basin, China." Interpretation 6, no. 2 (May 1, 2018): T431—T447. http://dx.doi.org/10.1190/int-2017-0159.1.
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Volcanic reservoirs have been overlooked for hydrocarbon exploration for a long time. Carboniferous volcanic rocks of the Zhongguai paleouplift contain proven reserves of [Formula: see text]. We have investigated the volcanic reservoirs integrating cores, well, and seismic data, and the proposed volcanic reservoir distribution is controlled by the weathering function, fractures, and lithology. The weathering process makes the originally tight igneous rocks become good-quality reservoirs, and fractures play an important role in connecting different types of pores and act as reservoir space. Isolated and ineffective pores become effective ones due to connection among fractures. Only volcanic breccia can be good-quality reservoirs without any weathering function. The nonlinear chaos inversion controlled by weathered layers shows that the good-quality reservoirs are distributed in the top of the weathering crust and the structural high. Furthermore, fluid-detection attributes and background information prove that oil and gas are distributed along the paleostructural high. The objectives of this study were to (1) describe the characteristics of volcanic reservoirs and determine the controlled rules for reservoir distribution, (2) characterize the distribution of reservoirs and hydrocarbon, and (3) propose an effective workflow for hydrocarbon exploration in volcanic rocks combining geologic and geophysical methods.
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Lawal, Kazeem A., Asekhame U. Yadua, Mathilda I. Ovuru, Oluchukwu M. Okoh, Stella I. Eyitayo, Saka Matemilola, and Olugbenga Olamigoke. "Rapid screening of oil-rim reservoirs for development and management." Journal of Petroleum Exploration and Production Technology 10, no. 3 (December 2, 2019): 1155–68. http://dx.doi.org/10.1007/s13202-019-00810-6.
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AbstractAs an improvement over existing screening techniques, we introduce the relative mobile energy of primary gas-cap to the aquifer (Egw) as a new parameter for characterizing the performance of oil-rim reservoirs. Egw integrates key static and dynamic reservoir properties. To account for the time value of production, the framework allows maximizing the discounted recovery factor (DRF) of oil, gas or total hydrocarbon as the objective function. Employing detailed simulations of different well-defined oil-rim models, DRFs of oil, gas and total hydrocarbons have been correlated against Egw for common development concepts and well types. These correlations have resulted in a new screening technique for both green and brown oil-rim reservoirs. In addition to presenting simple generic charts for quick evaluation of oil-rim reservoirs, the main contributions of this work include the introduction of Egw as a new performance-characterizing parameter, and the flexibility to consider the DRF of any of oil, gas or total hydrocarbon as the basis for screening an oil-rim reservoir for development planning and field management. Using the example of a brown oil-rim reservoir, the applicability and robustness of the new screening technique are demonstrated.
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Ayala, Luis F., Turgay Ertekin, and Michael A. Adewumi. "Compositional Modeling of Retrograde Gas-Condensate Reservoirs in Multimechanistic Flow Domains." SPE Journal 11, no. 04 (December 1, 2006): 480–87. http://dx.doi.org/10.2118/94856-pa.
Full textAbstract:
Summary A multimechanistic flow environment is the result of the combined action of a Darcian flow component (the macroscopic flow of the phase caused by pressure gradients) and a Fickian-like or diffusive flow component (diffusive flow caused by molecular concentration gradients) taking place in a hydrocarbon reservoir. The present work presents the framework needed for the assessment of the impact of multimechanistic flow on systems where complex fluid behavior—such as that of retrograde gas-condensate fluids—requires the implementation of compositional reservoir simulators. Because of the complex fluid behavior nature of gas-condensate fluids, a fully-implicit (IMPISC-type) compositional model is implemented and the model is used for the study of the isothermal depletion of naturally fractured retrograde gas reservoirs. In these systems, especially those tight systems with very low permeability (k < 0.1 md), bulk fluid flow as predicted by Darcy's law might not take place despite the presence of large pressure gradients. The use of an effective diffusion coefficient in the gas phase—which accounts for the combined effect of the different diffusion mechanisms that could take place in a porous medium—and its relative contribution to fluid recovery is discussed. The compositional tracking capabilities of the model are tested, and the conditions where Fickian flow can be the major player in recovery predictions and considerably overcome the flow impairment to gas flow posed by the eventual appearance of a condensate barrier—typical of gas-condensate systems—are investigated. Finally, a mapping that defines different domains where multimechanistic flow can be expected in compositional simulators of retrograde gas-condensate reservoirs is presented. Introduction In typical natural-gas reservoirs, all hydrocarbons exist as a single free gas phase at conditions of discovery. Depending on the composition of the initial hydrocarbon mixture in place and their depletion behavior, we recognize up to three kinds of natural gas reservoirs: dry gas reservoirs, wet gas reservoirs, and retrograde gas or gas-condensate reservoirs. The latter is the richest in terms of heavy hydrocarbons, and thus it is very likely to develop a second heavier hydrocarbon phase (liquid condensate) upon isothermal depletion. This situation is illustrated by Fig. 1. In contrast, dry gases and wet gases do not undergo phase changes upon reservoir depletion, as their phase envelope's cricondentherms are found to the left of the reservoir temperature isotherm.
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Wang, Ziyi, Zhiqian Gao, Tailiang Fan, Hehang Zhang, Lixin Qi, and Lu Yun. "Hydrocarbon-bearing characteristics of the SB1 strike-slip fault zone in the north of the Shuntuo Low Uplift, Tarim Basin." Petroleum Geoscience 27, no. 1 (July 1, 2020): petgeo2019–144. http://dx.doi.org/10.1144/petgeo2019-144.
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The SB1 strike-slip fault zone, which developed in the north of the Shuntuo Low Uplift of the Tarim Basin, plays an essential role in reservoir formation and hydrocarbon accumulation in deep Ordovician carbonate rocks. In this research, through the analysis of high-quality 3D seismic volumes, outcrop, drilling and production data, the hydrocarbon-bearing characteristics of the SB1 fault are systematically studied. The SB1 fault developed sequentially in the Paleozoic and formed as a result of a three-fold evolution: Middle Caledonian (phase III), Late Caledonian–Early Hercynian and Middle–Late Hercynian. Multiple fault activities are beneficial to reservoir development and hydrocarbon filling. In the Middle–Lower Ordovician carbonate strata, linear shear structures without deformation segments, pull-apart structure segments and push-up structure segments alternately developed along the SB1 fault. Pull-apart structure segments are the most favourable areas for oil and gas accumulation. The tight fault core in the centre of the strike-slip fault zone is typically a low-permeability barrier, whilst the damage zones on both sides of the fault core are migration pathways and accumulation traps for hydrocarbons, leading to heterogeneity in the reservoirs controlled by the SB1 fault. This study provides a reference for hydrocarbon exploration and development of similar deep-marine carbonate reservoirs controlled by strike-slip faults in the Tarim Basin and similar ancient hydrocarbon-rich basins.
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Yusubov, N. P., and T. N. Shikhmammadova. "Hydrocarbon system of the South Caspian Depression." Geofizicheskiy Zhurnal 44, no. 3 (August 24, 2022): 87–95. http://dx.doi.org/10.24028/gj.v44i3.261971.
Full textAbstract:
Actuality. The hydrocarbon generation sources in the South Caspian Basin (SCB) are located at the depth of nine or more kilometers, where the organic-rich Maikop sediments occur. The main oil-and-gas fields here are found in reservoirs of the Productive Strata (Lower Pliocene), bedding at a depth of one or more kilometers. At the same time, the significant role at the process of hydrocarbons migration from the source of their generation to the reservoirs belongs to the tectonic faults (fractures). However, the results of the research according to the latest seismic data carried out in recent years are indicated the unavailability of the tectonic faults in the SCB, which connected the hydrocarbon generation sources with the reservoirs in the Productive Strata.
Target. The determination of the geological elements at the studied area that contributed the role of the hydrocarbon migration channels and connected generation source with reservoirs in the Productive Strata.
Objects. The hydrocarbon generation source, hydrocarbon migration channel, tectonic faults and fractures, Productive Strata reservoirs, eruptive channels of the mud volcanoes.
Approach. The collaboration interpretation results of the deep drilling and the seismic data by using the common depth point method.
Results. Based on the structural interpretation results of the seismic data with high-resolution parameters, are indicated the lack of the tectonic faults which connecting the hydrocarbon generation source with reservoirs of the Productive Strata in the SCB.
In addition, the hydrocarbons that generated in the Maikop sediments are transported to the Productive Strata reservoirs by the eruptive channels of mud volcanoes. The opinion that the process of hydrocarbon generation in the Maikop clay deposits continues to the present time and the mud volcanoes eruptive channels provide feeding of the deposits with the continuous supply of oil-and-gas was expressed. Such kind of mechanism allows to classify the deposits, that more than a century under developed in the South Caspian Depression and which located at the zone of mud volcanomaturity, to the category of replenished.
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Tagiyev, M. F., and I. N. Askerov. "Geologic-geochemical and modelling studies of hydrocarbon migration in the South Caspian basin." Azerbaijan Oil Industry, no. 10 (October 15, 2020): 4–15. http://dx.doi.org/10.37474/0365-8554/2020-10-4-15.
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Based on pyrolysis data an overview is given on the generative potential and maturity of individual stratigraphic units in the South Caspian sedimentary cover. Furthermore, the pyrolysis analyses indicate that the Lower Pliocene Productive Series being immature itself is likely to have received hydrocarbon charge from the underlying older strata. The present state of the art in studying hydrocarbon migration and the "source-accumulation" type relationship between source sediments and reservoired oils in the South Caspian basin are touched upon. The views of and geochemical arguments by different authors for charging the Lower Pliocene Productive Series reservoirs with hydrocarbons from the underlying Oligocene-Miocene source layers are presented. Quantitative aspects of hydrocarbon generation, fluid dynamics, and formation of anomalous temperature & pressure fields based on the results of basin modelling in Azerbaijan are considered. Based on geochemical data analysis and modelling studies, as well as honouring reports by other workers the importance and necessity of upward migration for hydrocarbon transfer from deep generation centers to reservoirs of the Productive Series are shown.
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G.E., Onyishi, Ugwu G.Z., and Onyishi S.E. "Reservoir Characterization of an Onshore Geofield in Niger Delta, Nigeria, using Offset Well Data." African Journal of Environment and Natural Science Research 6, no. 2 (July 16, 2023): 43–50. http://dx.doi.org/10.52589/ajensr-mcjhlepv.
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Three wells (GE_11, G_12 and G_13) in an onshore geofield in the Niger Delta, Nigeria, were used to characterise the reservoirs of the oil field. RokDoc (5.1) and Petrel (2014.1) software were employed for data analysis and characterisation of the reservoirs. A comprehensive petrophysical analysis of each well was carried out in other to ascertain the physical properties such as shale volume, porosity, fluid saturation, net pay thickness and gross pay thickness. The well information was also used to evaluate the lithology and hydrocarbon depth. The hydrocarbon depths in the reservoirs ranged from 3292 to 4121 m, while the hydrocarbon saturation ranged from 0.671 to 0.982. The water saturation ranges from 0.042 to 0.446, while the porosity ranges from 0.145 to 0.216. The bulk volume of water was estimated to vary from 0.015 to 0.025. The reservoir units across the three wells have parameters detailing a characteristically hydrocarbon-bearing reservoir.
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Efemena, O. O., and C. U. Ugwueze. "Hydrocarbon production potential of paralic reservoirs from the Niger Delta basin: Evidence from ichnological studies." Scientia Africana 23, no. 2 (May 14, 2024): 80–87. http://dx.doi.org/10.4314/sa.v23i2.8.
Full textAbstract:
Reservoir ichnological study was employed to improve on the inconsistencies and poor interpretation of hydrocarbon-bearing strata within the multipartite maturing terrain of the onshore Niger Delta basin. Ichnofacies characterization revealed two distinctive trace fossil suites that both reflected different feeding behaviours and responses to substrate consistency, which assisted in the high-resolution assessment of facies constituting the paralic reservoirs. Fifteen potential reservoir intervals were subdivided into productive and non-productive as revealed on core slabs as well as well log signatures. Fluctuating river sediment influx has been considered to be detrimental to the colonization of the channel deposits and barrier bars, which resulted in excellent hydrocarbon reservoirs in the study area. The sandstone facies, characterized by sparse bioturbation and extensive bedding, displays imprints of Ophiomorpha, Thalassinoides, and Palaeophycus. The removal of these imprints has minimized subtle heterogeneities, resulting in more uniform reservoir characteristics. This uniformity has favored the accumulation of hydrocarbons within the point bars.Biogenicchurning of bedded sediment generated a poorer sorting index thereby reducing the reservoir quality at 9866-9840ft, 9154-9120ft, and 9090- 060ft depth intervals, which has been interpreted to represent poor reservoir potentials. However, it is advised that future investigations should focus on the forced regressive shoreface and delta front reservoirs of the studied interval for its internal continuity that may contain maximum production potential.
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Chen, Fangwen, Shuangfang Lu, and Xue Ding. "Organoporosity Evaluation of Shale: A Case Study of the Lower Silurian Longmaxi Shale in Southeast Chongqing, China." Scientific World Journal 2014 (2014): 1–9. http://dx.doi.org/10.1155/2014/893520.
Full textAbstract:
The organopores play an important role in determining total volume of hydrocarbons in shale gas reservoir. The Lower Silurian Longmaxi Shale in southeast Chongqing was selected as a case to confirm the contribution of organopores (microscale and nanoscale pores within organic matters in shale) formed by hydrocarbon generation to total volume of hydrocarbons in shale gas reservoir. Using the material balance principle combined with chemical kinetics methods, an evaluation model of organoporosity for shale gas reservoirs was established. The results indicate that there are four important model parameters to consider when evaluating organoporosity in shale: the original organic carbon (w(TOC0)), the original hydrogen index (IH0), the transformation ratio of generated hydrocarbon (F(Ro)), and the organopore correction coefficient (C). The organoporosity of the Lower Silurian Longmaxi Shale in the Py1 well is from 0.20 to 2.76%, and the average value is 1.25%. The organoporosity variation trends and the residual organic carbon of Longmaxi Shale are consistent in section. The residual organic carbon is indicative of the relative levels of organoporosity, while the samples are in the same shale reservoirs with similar buried depths.
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Maju-Oyovwikowhe, E. G., and E. J. Ighodaro. "Petrophysical properties and volume estimation of hydrocarbon resources in x field, onshore niger delta: A reservoir characterization study." Scientia Africana 22, no. 1 (May 31, 2023): 151–74. http://dx.doi.org/10.4314/sa.v22i1.14.
Full textAbstract:
A reservoir characterization study was conducted on three wells located in X Field, situated in the Onshore region of the Niger Delta. A suite of conventional digital well logs was utilized to identify hydrocarbon-bearing reservoirs, determine reservoir petrophysical parameters, and infer the depositional environment. The study delineated four hydrocarbon-bearing reservoirs, labeled A, B, C, and D, with porosity estimates ranging from 25% to 27%, and permeability values varying from 1863.22md to 2759.78md. These results suggest that the reservoirs have good storage capacity and permit free flow of fluids, consistent with prior research in the Niger Delta. The water saturation values, ranging from 43% to 70% for Well X and 53% to 94% for Well Y, indicate the presence of significant hydrocarbon in reservoir C, while Well Z did not contain any hydrocarbon. The estimation of oil and gas resources indicated that Well X contains 1.11 X 105 barrels/acre of oil and 5.16 X 107 cubic feet/acre of gas, while Well Y contains 4.43 X 106 cubic feet of gas. The analysis of the volume of shale (0.15-0.19) revealed that the reservoirs range from slightly shaly sand to shaly sand. Based on the log motifs, the study suggests that the reservoirs are mainly fluvial channel deposits, and the rapid alternation of thin beds of sand and shale indicates deposits of delta progradation and river floodplain deposits.
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Enamekere Umoh, Ekaete, Peace Oluwaseyi Agbaje, and Joseph Oluwaseun Akinade. "Hydrocarbon Formation Evaluation Using Well Log Data Of Well Tmg-02, Opolo Field, Niger Delta." Global Journal of Pure and Applied Sciences 29, no. 2 (September 29, 2023): 165–74. http://dx.doi.org/10.4314/gjpas.v29i2.7.
Full textAbstract:
Well TMG-02 with the depth interval of 5058.77 to 9389.43ft of Opolo field located in the Niger delta was assessed for hydrocarbon using suite of geophysical well logs. Suite includes gamma ray (GR), formation density (RHOB), neutron porosity (NPHI), and resistivity logs. The analysis was carried out to estimate the field’s hydrocarbon prospect by identifying hydrocarbon bearing reservoirs and their properties. The quantitative and qualitative results, identified thicker units of sand than shale lithology, three reservoirs A, B, C within the depth ranges from 5058.77ft to 9389.43ft, capable of accumulating hydrocarbon based on the petrophysical parameters calculated were delineated. The effective porosity for each of the reservoir are: 27%, 24% and 19% respectively. It was observed that reservoir A, B had excellent permeability while reservoir C was low as a result of thicker shale sequence within the reservoir. The result obtained shows presence of hydrocarbon bearing gas water contact in Reservoir A at depth of 5119.70ft, gas oil contact and oil water contact at depths 7310.00ft and 7438.69ft in Reservoir B and Gas water contact at depth 9032.00ft at Reservoir C.
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Malvić, Tomislav, Josip Ivšinović, Josipa Velić, Jasenka Sremac, and Uroš Barudžija. "Increasing Efficiency of Field Water Re-Injection during Water-Flooding in Mature Hydrocarbon Reservoirs: A Case Study from the Sava Depression, Northern Croatia." Sustainability 12, no. 3 (January 21, 2020): 786. http://dx.doi.org/10.3390/su12030786.
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The authors analyse the process of water re-injection in the hydrocarbon reservoirs/fields in the Upper Miocene sandstone reservoirs, located in the western part of the Sava Depression (Croatia). Namely, this is the “A” field with “L” reservoir that currently produces hydrocarbons using a secondary recovery method, i.e., water injection (in fact, re-injection of the field waters). Three regional reservoir variables were analysed: Porosity, permeability and injected water volumes. The quantity of data was small for porosity reservoir “L” and included 25 points; for permeability and injected volumes of water, 10 points each were measured. This study defined selection of mapping algorithms among methods designed for small datasets (fewer than 20 points). Namely, those are inverse distance weighting and nearest and natural neighbourhood. Results were tested using cross-validation and isoline shape recognition, and the inverse distance weighting method is described as the most appropriate approach for mapping permeability and injected volumes in reservoir “L”. Obtained maps made possible the application of the modified geological probability calculation as a tool for prediction of success for future injection (with probability of 0.56). Consequently, it was possible to plan future injection more efficiently, with smaller injected volumes and higher hydrocarbon recovery. Prevention of useless injection, decreasing number of injection wells, saving energy and funds invested in such processes lead to lower environmental impact during the hydrocarbon production.
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Bawahab, Mohammed, and Dmour Hazim. "Performance Analysis of a Water-Drive Oil Reservoir: An Oilfield Case Study." Geosciences and Engineering 11, no. 1 (October 27, 2023): 117–32. http://dx.doi.org/10.33030/geosciences.2023.01.010.
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One of the primary responsibilities of a reservoir engineer is to evaluate the performance of hydrocarbon reservoirs to estimate the original hydrocarbons in place, reserves, ultimate oil/gas recovery factor. This responsibility becomes complicated in the case of water-drive reservoirs due to the high uncertainty associated with aquifer properties, including rock properties and aquifer geometry. This paper presents a new method to find the optimum aquifer model based on the root mean square error (RMSE) values by using MBAL software. The study investigated the transmissibility between the X, Y, and Z reservoirs in the field. Additionally, the original oil-in-place (OOIP) was estimated by using material balance equation and Monte Carlo concepts.
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Pitakbunkate, T., P. B. Balbuena, G. J. Moridis, and T. A. Blasingame. "Effect of Confinement on Pressure/Volume/Temperature Properties of Hydrocarbons in Shale Reservoirs." SPE Journal 21, no. 02 (April 14, 2016): 621–34. http://dx.doi.org/10.2118/170685-pa.
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Summary Shale reservoirs play an important role as a future energy resource of the United States. Numerous studies were performed to describe the storage and transport of hydrocarbons through ultrasmall pores in the shale reservoirs. Most of these studies were developed by modifying techniques used for conventional reservoirs. The common pore-size distribution of the shale reservoirs is approximately 1 to 20 nm and in such confined spaces that the interactions between the wall of the container (i.e., the shale and kerogen) and the contained fluids (i.e., the hydrocarbon fluids and water) may exert significant influence on the localized phase behavior. We believe this is because the orientation and distribution of fluid molecules in the confined space are different from those of the bulk fluid, causing changes in the localized thermodynamic properties. This study provides a detailed account of the changes of pressure/volume/temperature properties and phase behavior (specifically, the phase diagrams) in a synthetic shale reservoir for pure hydrocarbons (methane and ethane) and a simple methane/ethane (binary) mixture. Grand canonical Monte Carlo (GCMC) simulations are performed to study the effect of confinement on the fluid properties. A graphite slab made of two layers is used to represent kerogen in the shale reservoirs. The separation between the two layers, representing a kerogen pore, is varied from 1 to 10 nm to observe the changes of the hydrocarbon-fluid properties. In this paper, the critical properties of methane and ethane as well as the methane/ethane mixture phase diagrams in different pore sizes are derived from the GCMC simulations. In addition, the GCMC simulations are used to investigate the deviations of the fluid densities in the confined space from those of the bulk fluids at reservoir conditions. Although not investigated in this work, such deviations may indicate that significant errors for production forecasting and reserves estimation in shale reservoirs may occur if the (typical) bulk densities are used in reservoir-engineering calculations.
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Alharthy, Najeeb S., Tadesse W. Teklu, Thanh N. Nguyen, Hossein Kazemi, and Ramona M. Graves. "Nanopore Compositional Modeling in Unconventional Shale Reservoirs." SPE Reservoir Evaluation & Engineering 19, no. 03 (May 7, 2016): 415–28. http://dx.doi.org/10.2118/166306-pa.
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Summary Understanding the mechanism of multicomponent mass transport in the nanopores of unconventional reservoirs, such as Eagle Ford, Niobrara, Woodford, and Bakken, is of great interest because it influences long-term economic development of such reservoirs. Thus, we began to examine the phase behavior and flow characteristics of multicomponent flow in primary production in nanoporous reservoirs. Besides primary recovery, our long-term objectives included enhanced oil production from such reservoirs. The first step was to evaluate the phase behavior in nanopores on the basis of pore-size distribution. This was motivated because the physical properties of hydrocarbon components are affected by wall proximity in nanopores as a result of van der Waals molecular interactions with the pore walls. For instance, critical pressure and temperature of hydrocarbon components shift to lower values as the nanopore walls become closer. In our research, we applied this kind of critical property shift to the hydrocarbon components of two Eagle Ford fluid samples. Then, we used the shifted phase characteristics in dual-porosity compositional modeling to determine the pore-to-pore flow characteristics, and, eventually, the flow behavior of hydrocarbons to the wells. In the simulation, we assigned three levels of phase behavior in the matrix and fracture pore spaces. In addition, the flow hierarchy included flow from matrix (nano-, meso-, and macropores) to macrofractures, from macrofractures to a hydraulic fracture (HF), and through the HF to the production well. From the simulation study, we determined why hydrocarbon fluids flow so effectively in ultralow-permeability shale reservoirs. The simulation also gave credence to the intuitive notion that favorable phase behavior (phase split) in the nanopores is one of the major reasons for production of commercial quantities of light oil and gas from shale reservoirs. It was determined that the implementation of confined-pore and midconfined-pore phase behavior lowers the bubblepoint pressure, and this, in turn, leads to a slightly higher oil recovery and lesser gas recovery. Also it was determined that the implementation of midconfined-pore and confined-pore phase-behavior shift reduces the retrograde liquid-condensation region, which in turn, leads to lower liquid yield while maintaining the same gas-production quantity. Finally, the important reason that we are able to produce shale reservoirs economically is “rubblizing” the reservoir matrix near HFs, which creates favorable permeability pathways to improve reservoir drainage. This is why multistage hydraulic fracturing is so critical for successful development of shale reservoirs.
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Jamalbayov, M. A., Kh M. Ibrahimov, and T. M. Jamalbayli. "Determination the initial value and change behaviour of the reservoir permeability via two field measurements." SOCAR Proceedings, no. 4 (December 31, 2021): 72–79. http://dx.doi.org/10.5510/ogp20210400616.
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The paper proposes a technique for interpreting the results of hydrodynamic studies of volatile and non-volatile oil wells at two steady-state regimes in order to determine the initial value and coefficient of variation in effective permeability of the reservoir. It is developed based on a binary filtration model, where the hydrocarbon system is represented as consisting of two pseudocomponents and two phases, between which mass transfer of hydrocarbons takes place. The proposed methodology requires well flow rates measured at two different steady-state well conditions for two different reservoir pressures and thermodynamic data of the hydrocarbon system at reservoir conditions. The methodology has been validated using examples of hypothetical volatile and non-volatile oil reservoirs at different rock deformation ratios and for nondeformable reservoirs. It has also been tested under different development stages and measurement conditions. For this purpose, a computer simulation of the oil reservoir depletion process was carried out, the results of which were used as well test data. Satisfactory accuracy and reliability of the outlined approach has been established. As deviations of calculated values of required parameters from their actual values did not exceed 8%.
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Liang, Tianbo, Rafael A. Longoria, Jun Lu, Quoc P. Nguyen, and David A. DiCarlo. "Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives." SPE Journal 22, no. 04 (May 17, 2017): 1011–23. http://dx.doi.org/10.2118/175101-pa.
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Summary Fracturing-fluid loss into the formation can potentially damage hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field to dissipate the lost water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants have potential to reduce the effect of fracturing-fluid loss on hydrocarbon permeability in the matrix. Unconventional tight reservoirs can differ significantly from one another, which could make the use of these techniques effective in some cases but not in others. We present an experimental investigation dependent on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants for hydrocarbon permeability for different initial reservoir conditions (IRCs). From this work, we identify the mechanism responsible for the permeability reduction in the matrix, and we suggest criteria that can be used to optimize fracturing-fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.
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Wang, Zhenliang, Shengdong Xiao, Feilong Wang, Guomin Tang, Liwen Zhu, and Zilong Zhao. "Phase Behavior Identification and Formation Mechanisms of the BZ19-6 Condensate Gas Reservoir in the Deep Bozhong Sag, Bohai Bay Basin, Eastern China." Geofluids 2021 (July 2, 2021): 1–19. http://dx.doi.org/10.1155/2021/6622795.
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Significant developments have been observed in recent years, in the field of deep part exploration in the Bozhong Sag, Bohai Bay Basin in eastern China. The BZ19-6 large condensate gas field, the largest gas field in the Bohai Bay Basin, was discovered for the first time in a typical oil-type basin. The proven oil and gas geological reserves in the deeply buried hills of the Archean metamorphic rocks, amount to approximately 3 × 10 8 tons of oil equivalent. However, the phase behavior and genetic mechanisms of hydrocarbon fluids are still unclear. In this study, the phase diagram identification method and various empirical statistical methods, such as the block diagram method, φ 1 parameter method, rank number method, and Z -factor method were implemented to comprehensively identify the phase behavior types of the BZ19-6 condensate gas reservoir. The genetic mechanism of the BZ19-6 condensate gas reservoir was investigated in detail through analyses of physical properties of the fluid at high temperatures and pressures, organic geochemical characteristics of condensate oil and gas, and regional tectonic background. Consequently, this study is shown as follows: (1) The BZ19-6 condensate gas reservoir is a part of a secondary condensate gas reservoir with oil rings, formed synthetically since the Neogene period due to multiple factors, such as retrograde evaporation from deep burial and high temperature, inorganic CO2 charging from the deep mantle, and late natural gas invasion. (2) The hydrocarbon accumulation process of the BZ19-6 condensate gas reservoir is as follows: First, a large amount of oil is accumulated at the end of the lower Minghuazhen deposition (5 Ma BP); second, a large amount of natural gas is generated in the deep-source kitchen and mantle-derived inorganic CO2 charged into the early formed oil reservoirs at the end of the upper Minghuazhen deposition (2 Ma BP). As a result, the content of gaseous hydrocarbons in the hydrocarbon system of the reservoir increased, which led to large amounts of liquid hydrocarbons dissolved in gaseous hydrocarbons and significantly reduced the critical temperature of the hydrocarbon system. Therefore, existing secondary condensate gas reservoirs are formed when the critical temperature is lower than the formation temperature and it enters the critical condensate temperature range.
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Liu, Xiaoping, Zhijun Jin, Guoping Bai, Jie Liu, Ming Guan, Qinghua Pan, and Ting Li. "A comparative study of salient petroleum features of the Proterozoic–Lower Paleozoic succession in major petroliferous basins in the world." Energy Exploration & Exploitation 35, no. 1 (December 11, 2016): 54–74. http://dx.doi.org/10.1177/0144598716680308.
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The Proterozoic–Lower Paleozoic marine facies successions are developed in more than 20 basins with low exploration degree in the world. Some large-scale carbonate oil and gas fields have been found in the oldest succession in the Tarim Basin, Ordos Basin, Sichuan Basin, Permian Basin, Williston Basin, Michigan Basin, East Siberia Basin, and the Oman Basin. In order to reveal the hydrocarbon enrichment roles in the oldest succession, basin formation and evolution, hydrocarbon accumulation elements, and processes in the eight major basins are studied comparatively. The Williston Basin and Michigan Basin remained as stable cratonic basins after formation in the early Paleozoic, while the others developed into superimposed basins undergone multistage tectonic movements. The eight basins were mainly carbonate deposits in the Proterozoic–early Paleozoic having different sizes, frequent uplift, and subsidence leading to several regional unconformities. The main source rock is shale with total organic carbon content of generally greater than 1% and type I/II organic matters. Various types of reservoirs, such as karst reservoir, dolomite reservoir, reef-beach body reservoirs are developed. The reservoir spaces are mainly intergranular pore, intercrystalline pore, dissolved pore, and fracture. The reservoirs are highly heterogeneous with physical property changing greatly and consist mainly of gypsum-salt and shale cap rocks. The trap types can be divided into structural, stratigraphic, lithological, and complex types. The oil and gas reservoir types are classified according to trap types where the structural reservoirs are mostly developed. Many sets of source rocks are developed in these basins and experienced multistage hydrocarbon generation and expulsion processes. In different basins, the hydrocarbon accumulation processes are different and can be classified into two types, one is the process through multistage hydrocarbon accumulation with multistage adjustment and the other is the process through early hydrocarbon accumulation and late preservation.
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Lyu, Qixia, Weiming Wang, Qingchun Jiang, Haifeng Yang, Hai Deng, Jun Zhu, Qingguo Liu, and Tingting Li. "Basement Reservoirs in China: Distribution and Factors Controlling Hydrocarbon Accumulation." Minerals 13, no. 8 (August 9, 2023): 1052. http://dx.doi.org/10.3390/min13081052.
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The oil reserves of global basement reservoirs are 248 × 108 t and natural gas reserves are 2681 × 108 m3; they are crucial links in the future oil and natural gas exploration field and play an irreplaceable role in increasing oil and natural gas reserves and production. Based on research on the definition and classification of basement reservoirs, this study dissected three major basement reservoirs in China (i.e., the Dongping region located in the Qaidam Basin, the Bozhong 19-6 gas field located the Bohai Bay Basin, and the Central Uplift area of the Songliao Basin). The geological conditions and controlling factors of oil and natural gas accumulation in basement reservoirs in China are summarized. The results of this study are as follows: (1) Basement reservoirs can be classified into three distinct types, namely, the weathered carapace type, weathered inner type, and weathered composite type. They are characterized by a large burial depth, strong concealment, and huge reserves and are mostly distributed at the margins of continental plates and in zones with stratum intensive tectonic activity; (2) Basement reservoirs in different basins have different controlling factors. The basement reservoir in the Dongping region, located in the Qaidam Basin, has favorable geological conditions with laterally connected sources and reservoirs. In this reservoir, oil and natural gas have transferred along faults and unconformities to accumulate in uplifted areas, forming a weathered carapace-type basement reservoir controlled by structures. The Bozhong 19-6 gas field, which is situated in the Bohai Bay Basin, has favorable multiple hydrocarbon supplies of source rocks. Under the communication of faults and cracks, oil resources form a weathered inner type basement reservoir. In the Central Uplift area of the Songliao Basin, the basement reservoir exhibits a dual-sided hydrocarbon supply condition from the uplift. In this reservoir, oil and natural gas have transferred to traps through the fault and inner fracture system and have been properly preserved thanks to the extensive overlying cap rocks. It can be concluded that, after being attenuated by millions of years of weathering and leaching, basement rocks can form large-scale and medium-scale basement reservoirs with reserves of more than 100 million barrels in the presence of favorable geological conditions, such as a multi-directional hydrocarbon supply, a high brittle mineral content in the reservoirs, diverse reservoir spaces, and high-quality cap rocks.
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Zhang, Bowei, and Guang Fu. "Prediction Method and Application of Hydrocarbon Fluid Migration through Faulted Cap Rocks." Energies 16, no. 1 (December 27, 2022): 290. http://dx.doi.org/10.3390/en16010290.
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Hydrocarbon fluid migration through faulted cap rocks was determined by comparing the maximum connected thickness of cap rocks required for hydrocarbon fluid migration and the actual values, since cap rocks are important in the study of hydrocarbon fluid distribution in petroliferous basins based on its migration mechanism(s). The maximum connected thickness required was identified by comparing the cap rocks, fault displacement, and oil/gas distribution. The hydrocarbon fluid at the Putaohua reservoir migrated to the overlying Saertu and Heidimiao reservoirs in the Bayan Chagan Area, northern Songliao Basin. This was predicted to demonstrate the validity of the method. The results show that the adjusted Putaohua oil reservoir was distributed near the Talahai fault and Bayanchagan fault, rather than the Gulong sag in the southwest of the study area, where oil migrated vertically through the Sapu cap rocks to the overlying Saertu reservoir. Thick mudstone cap rocks in the second member of the Nenjiang Formation made it difficult for hydrocarbon fluid to migrate to the Heidimiao reservoir. This agrees well with hydrocarbon fluid distribution at the Putaohua, Saertu, and Heidimiao reservoirs in the Bayan Chagan Area, indicating that this method is feasible for predicting hydrocarbon fluid migration through faulted cap rocks.
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He, Faqi, Ying Rao, Weihong Wang, and Yanghua Wang. "Prediction of hydrocarbon reservoirs within coal-bearing formations." Journal of Geophysics and Engineering 17, no. 3 (February 25, 2020): 484–92. http://dx.doi.org/10.1093/jge/gxaa007.
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Abstract This paper presents a case study on the prediction of hydrocarbon reservoirs within coal-bearing formations of the Upper Palaeozoic. The target reservoirs are low-permeability low-pressure tight-sandstone reservoirs in the Daniudi Gas Field, Ordos Basin, China. The prime difficulty in reservoir prediction is caused by the interbedding coal seams within the formations, which generate low-frequency strong-amplitude reflections in seismic profiles. To tackle this difficulty, first, we undertook a careful analysis regarding the stratigraphy and lithology of these coal-bearing formations within the study area. Then, we conducted a geostatistical inversion using 3D seismic data and obtained reservoir parameters including seismic impedance, gamma ray, porosity and density. Finally, we carried out a reservoir prediction in the coal-bearing formations, based on the reservoir parameters obtained from geostatistical inversion and combined with petrophysical analysis results. The prediction result is accurately matched with the actual gas-test data for the targeted four segments of the coal-bearing formations.