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1
Lü, Xiuxiang, Weiwei Jiao, Xinyuan Zhou, Jianjiao Li, Hongfeng Yu e Ning Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tazhong Uplift, Tarim Basin, Western China". Energy Exploration & Exploitation 27, n. 2 (aprile 2009): 69–90. http://dx.doi.org/10.1260/0144-5987.27.2.69.
Testo completoAbstract (sommario):
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.
2
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, n. 11 (26 ottobre 2022): 1357. http://dx.doi.org/10.3390/min12111357.
Testo completoAbstract (sommario):
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.
3
Chen, Junqing, Xiongqi Pang e 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, n. 10 (ottobre 2015): 880–92. http://dx.doi.org/10.1139/cjes-2014-0209.
Testo completoAbstract (sommario):
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.
4
Lerche, Ian. "Hydrocarbon Flow-up Intersecting Faults: Leakage/Production and Bypass Considerations". Energy Exploration & Exploitation 23, n. 4 (agosto 2005): 225–43. http://dx.doi.org/10.1260/014459805775219157.
Testo completoAbstract (sommario):
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.
5
Peng, Biao, Lulu Zhang, Jianfeng Li, Tiantian Chang e Zheng Zhang. "Multi-Type Hydrocarbon Accumulation Mechanism in the Hari Sag, Yingen Ejinaqi Basin, China". Energies 15, n. 11 (27 maggio 2022): 3968. http://dx.doi.org/10.3390/en15113968.
Testo completoAbstract (sommario):
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.
6
Rashid, Muhammad, Miao Luo, Umar Ashraf, Wakeel Hussain, Nafees Ali, Nosheen Rahman, Sartaj Hussain, Dmitriy A. Martyushev, Hung Vo Thanh e 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, n. 1 (24 dicembre 2022): 29. http://dx.doi.org/10.3390/min13010029.
Testo completoAbstract (sommario):
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.
7
Lerche, Ian. "Hydrocarbon Flow along Intersecting Faults". Energy Exploration & Exploitation 23, n. 2 (aprile 2005): 107–23. http://dx.doi.org/10.1260/0144598054529996.
Testo completoAbstract (sommario):
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.
8
Zhao, Shuangfeng, Wen Chen, Zhenhong Wang, Ting Li, Hongxing Wei e 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, n. 4 (22 febbraio 2018): 801–19. http://dx.doi.org/10.1177/0144598718759560.
Testo completoAbstract (sommario):
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.
9
Zhou, Tianqi, Chaodong Wu, Xutong Guan, Jialin Wang, Wen Zhu e 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, n. 23 (23 novembre 2021): 7832. http://dx.doi.org/10.3390/en14237832.
Testo completoAbstract (sommario):
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.
10
Sun, Yu, Shi Zhong Ma, Bai Quan Yan e Chen Chen. "Controlling Factors for Reservoirs Distribution of the Putaohua Oil Layer in the Saozhao Sag". Advanced Materials Research 616-618 (dicembre 2012): 816–20. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.816.
Testo completoAbstract (sommario):
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.
11
Jumiati, Wiwiek, David Maurich, Andi Wibowo e Indra Nurdiana. "The Development of Non-Conventional Oil and Gas in Indonesia". Journal of Earth Energy Engineering 9, n. 1 (19 aprile 2020): 11–16. http://dx.doi.org/10.25299/jeee.2020.4074.
Testo completoAbstract (sommario):
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.
12
Shi, Wen-rui, Chong Zhang, Shao-yang Yuan, Yu-long Chen e Lin-qi Zhu. "A Crossplot for Mud Logging Interpretation of Unconventional Gas Shale Reservoirs and its Application". Open Petroleum Engineering Journal 8, n. 1 (19 agosto 2015): 265–71. http://dx.doi.org/10.2174/1874834101508010265.
Testo completoAbstract (sommario):
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).
13
Hao, Hui Zhi, e 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 (marzo 2015): 859–62. http://dx.doi.org/10.4028/www.scientific.net/amm.737.859.
Testo completoAbstract (sommario):
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.
14
Chen, Mei Tao, Ning Yang e Shang Ming Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tahong Uplift Tarim Basin, Western China". Advanced Materials Research 403-408 (novembre 2011): 1511–16. http://dx.doi.org/10.4028/www.scientific.net/amr.403-408.1511.
Testo completoAbstract (sommario):
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.
15
Sun, Zhen, Zhen Yang, Xiaoning He, Cixuan Wan, Gang He, Qiang Ren, Shihu Zhao, Wei Cheng e Sisi Chen. "Geochemical Characteristics of Formation Water in Carbonate Reservoirs and Its Indication to Hydrocarbon Accumulation". Geofluids 2022 (11 ottobre 2022): 1–11. http://dx.doi.org/10.1155/2022/6095178.
Testo completoAbstract (sommario):
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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Ziemelis, Karl. "Hydrocarbon reservoirs". Nature 426, n. 6964 (novembre 2003): 317. http://dx.doi.org/10.1038/426317a.
Testo completo
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Neff, Dennis B. "Incremental pay thickness modeling of hydrocarbon reservoirs". GEOPHYSICS 55, n. 5 (maggio 1990): 556–66. http://dx.doi.org/10.1190/1.1442867.
Testo completoAbstract (sommario):
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 e G. A. Kalmykov. "Structure of continues reservoirs in the Domanik formation and petrophysical interpretation methods". Moscow University Bulletin. Series 4. Geology 1, n. 6 (29 gennaio 2022): 120–32. http://dx.doi.org/10.33623/0579-9406-2021-6-120-132.
Testo completoAbstract (sommario):
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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Zhang, Yuanyuan, Zhanli Ren, Youlu Jiang e Jingdong Liu. "Differential hydrocarbon enrichment in deep Paleogene tight sandstones of the Dongpu Depression in Eastern China". Energy Exploration & Exploitation 39, n. 3 (21 gennaio 2021): 797–814. http://dx.doi.org/10.1177/0144598720988112.
Testo completoAbstract (sommario):
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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Junira, Adi, e Andy Setyo Wibowo. "SHALE AS HYDROCARBON RESERVOIRS". Scientific Contributions Oil and Gas 39, n. 2 (8 ottobre 2018): 71–75. http://dx.doi.org/10.29017/scog.39.2.104.
Testo completoAbstract (sommario):
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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Fu, Siyi, Zhiwei Liao, Anqing Chen e 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, n. 2 (19 agosto 2019): 348–71. http://dx.doi.org/10.1177/0144598719870257.
Testo completoAbstract (sommario):
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., e S. Inichinbia. "Lithology and Fluid discrimination of Sody field of the Nigerian Delta". Journal of Applied Sciences and Environmental Management 24, n. 8 (9 settembre 2020): 1321–27. http://dx.doi.org/10.4314/jasem.v24i8.3.
Testo completoAbstract (sommario):
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
23
D., Imikanasua, Tamunobereton-Ari I e 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, n. 01 (2022): 142–51. http://dx.doi.org/10.38177/ajast.2022.6117.
Testo completoAbstract (sommario):
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.
24
Collen, J. D. "Diagenetic Control of Porosity and Permeability in Pakawau and Kapuni Group Sandstones, Taranaki Basin, New Zealand". Energy Exploration & Exploitation 6, n. 3 (giugno 1988): 263–80. http://dx.doi.org/10.1177/014459878800600307.
Testo completoAbstract (sommario):
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.
25
Sun, Xiaoming, Siyuan Cao, Xiao Pan, Xiangyang Hou, Hui Gao e 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, n. 2 (1 maggio 2018): T431—T447. http://dx.doi.org/10.1190/int-2017-0159.1.
Testo completoAbstract (sommario):
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.
26
Lawal, Kazeem A., Asekhame U. Yadua, Mathilda I. Ovuru, Oluchukwu M. Okoh, Stella I. Eyitayo, Saka Matemilola e Olugbenga Olamigoke. "Rapid screening of oil-rim reservoirs for development and management". Journal of Petroleum Exploration and Production Technology 10, n. 3 (2 dicembre 2019): 1155–68. http://dx.doi.org/10.1007/s13202-019-00810-6.
Testo completoAbstract (sommario):
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.
27
Ayala, Luis F., Turgay Ertekin e Michael A. Adewumi. "Compositional Modeling of Retrograde Gas-Condensate Reservoirs in Multimechanistic Flow Domains". SPE Journal 11, n. 04 (1 dicembre 2006): 480–87. http://dx.doi.org/10.2118/94856-pa.
Testo completoAbstract (sommario):
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.
28
Yusubov, N. P., e T. N. Shikhmammadova. "Hydrocarbon system of the South Caspian Depression". Geofizicheskiy Zhurnal 44, n. 3 (24 agosto 2022): 87–95. http://dx.doi.org/10.24028/gj.v44i3.261971.
Testo completoAbstract (sommario):
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.
29
Wang, Ziyi, Zhiqian Gao, Tailiang Fan, Hehang Zhang, Lixin Qi e 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, n. 1 (1 luglio 2020): petgeo2019–144. http://dx.doi.org/10.1144/petgeo2019-144.
Testo completoAbstract (sommario):
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.
30
Tagiyev, M. F., e I. N. Askerov. "Geologic-geochemical and modelling studies of hydrocarbon migration in the South Caspian basin". Azerbaijan Oil Industry, n. 10 (15 ottobre 2020): 4–15. http://dx.doi.org/10.37474/0365-8554/2020-10-4-15.
Testo completoAbstract (sommario):
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.
31
Chen, Fangwen, Shuangfang Lu e 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.
Testo completoAbstract (sommario):
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.
32
Malvić, Tomislav, Josip Ivšinović, Josipa Velić, Jasenka Sremac e 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, n. 3 (21 gennaio 2020): 786. http://dx.doi.org/10.3390/su12030786.
Testo completoAbstract (sommario):
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.
33
Pitakbunkate, T., P. B. Balbuena, G. J. Moridis e T. A. Blasingame. "Effect of Confinement on Pressure/Volume/Temperature Properties of Hydrocarbons in Shale Reservoirs". SPE Journal 21, n. 02 (14 aprile 2016): 621–34. http://dx.doi.org/10.2118/170685-pa.
Testo completoAbstract (sommario):
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.
34
Alharthy, Najeeb S., Tadesse W. Teklu, Thanh N. Nguyen, Hossein Kazemi e Ramona M. Graves. "Nanopore Compositional Modeling in Unconventional Shale Reservoirs". SPE Reservoir Evaluation & Engineering 19, n. 03 (7 maggio 2016): 415–28. http://dx.doi.org/10.2118/166306-pa.
Testo completoAbstract (sommario):
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.
35
He, Faqi, Ying Rao, Weihong Wang e Yanghua Wang. "Prediction of hydrocarbon reservoirs within coal-bearing formations". Journal of Geophysics and Engineering 17, n. 3 (25 febbraio 2020): 484–92. http://dx.doi.org/10.1093/jge/gxaa007.
Testo completoAbstract (sommario):
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.
36
Jamalbayov, M. A., Kh M. Ibrahimov e T. M. Jamalbayli. "Determination the initial value and change behaviour of the reservoir permeability via two field measurements". SOCAR Proceedings, n. 4 (31 dicembre 2021): 72–79. http://dx.doi.org/10.5510/ogp20210400616.
Testo completoAbstract (sommario):
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%.
37
Liang, Tianbo, Rafael A. Longoria, Jun Lu, Quoc P. Nguyen e David A. DiCarlo. "Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives". SPE Journal 22, n. 04 (17 maggio 2017): 1011–23. http://dx.doi.org/10.2118/175101-pa.
Testo completoAbstract (sommario):
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.
38
Wang, Zhenliang, Shengdong Xiao, Feilong Wang, Guomin Tang, Liwen Zhu e 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 (2 luglio 2021): 1–19. http://dx.doi.org/10.1155/2021/6622795.
Testo completoAbstract (sommario):
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.
39
Liu, Xiaoping, Zhijun Jin, Guoping Bai, Jie Liu, Ming Guan, Qinghua Pan e 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, n. 1 (11 dicembre 2016): 54–74. http://dx.doi.org/10.1177/0144598716680308.
Testo completoAbstract (sommario):
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.
40
Zhang, Bowei, e Guang Fu. "Prediction Method and Application of Hydrocarbon Fluid Migration through Faulted Cap Rocks". Energies 16, n. 1 (27 dicembre 2022): 290. http://dx.doi.org/10.3390/en16010290.
Testo completoAbstract (sommario):
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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Hoffman, Monty, e James Crafton. "Multiphase flow in oil and gas reservoirs". Mountain Geologist 54, n. 1 (gennaio 2017): 5–14. http://dx.doi.org/10.31582/rmag.mg.54.1.5.
Testo completoAbstract (sommario):
The porous rocks that make up oil and gas reservoirs are composed of complex combinations of pores, pore throats, and fractures. Pore networks are groups of these void spaces that are connected by pathways that have the same fluid entry pressures. Any fluid movement in pore networks will be along the pathways that require the minimum energy expenditure. After emplacement of hydrocarbons in a reservoir, fluid saturations, capillary pressure, and energy are in equilibrium, a significant amount of the reservoir energy is stored at the interface between the fluids. Any mechanism that changes the pressure, volume, chemistry, or temperature of the fluids in the reservoir results in a state of energy non-equilibrium. Existing reservoir engineering equations do not address this non-equilibrium condition, but rather assume that all reservoirs are in equilibrium. The assumption of equilibrium results in incorrect descriptions of fluid flow in energy non-equilibrium reservoirs. This, coupled with the fact that drilling-induced permeability damage is common in these reservoirs, often results in incorrect conclusions regarding the potential producibility of the well. Relative permeability damage, damage that can change which fluids are produced from a hydrocarbon reservoir, can occur even in very permeable reservoirs. Use of dependent variables in reservoir analysis does not correctly describe the physics of fluid flow in the reservoir and will lead to potentially incorrect answers regarding producibility of the reservoir.
42
Liu, Q., H. Xu, Z. Lei, Z. Li, Y. Xiong, S. Li, B. Luo e D. Chen. "Fault Mesh Petroleum Plays in the Donghetang Area, Tabei Uplift, Tarim Basin, Northwestern China, and Its Significance for Hydrocarbon Exploration". Russian Geology and Geophysics 62, n. 07 (1 luglio 2021): 808–27. http://dx.doi.org/10.2113/rgg20183939.
Testo completoAbstract (sommario):
Abstract —The hydrocarbon formation mechanism and potential targets in clastic strata from the Tabei Uplift, Tarim Basin, are documented using the fault mesh petroleum plays theory, based on integrating seismic, well log, well core, and geochemical data. The reservoirs in the Donghetang area are typical allochthonous and far-source fault mesh petroleum plays. There are two sets of fault meshes in the study area: (1) the combination of the Donghe sandstone and Permian–Triassic strata and (2) the combination of the fourth and third formations in the Jurassic strata. The fault mesh petroleum play in the Jurassic is a secondary reservoir that originates from the Carboniferous Donghe sandstone reservoir adjustment based on source correlation. The fault mesh carrier systems show the fully connected, fault–unconformity–transient storage relay, fault–transient storage–unconformity relay, and transient storage–fault relay styles, according to the architecture of the fault mesh. Based on the characteristics of the fault mesh petroleum plays, the reservoirs are divided into three categories (upper-, inner-, and margin-transient storage styles) and 15 styles. Integrated analysis of the hydrocarbon generation and faulting time periods reveals that there were four periods of hydrocarbon charging, with the first three stages charging the reservoirs with oil and the last stage charging the reservoirs with gas. There are multiple stages of reservoir accumulation and adjustment in the fault mesh in the study area. These stages of fault mesh accumulation and adjustment are the main reason why the reservoir distribution multiple vertical units have different hydrocarbon properties. Fault-block and lithologic reservoirs related to the inner- and upper-transient storage styles are the main exploration targets in the clastic strata in the study area.
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Luo, Yong, Jian Guo Wu, Fang Zeng, Ding Jie Huang e Ya Dong Bai. "Characteristics of Hydrocarbon Accumulation of Putaohua Reservoir in Xingnan Area of Daqing Placanticline". Advanced Materials Research 962-965 (giugno 2014): 12–15. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.12.
Testo completoAbstract (sommario):
Through comprehensive study on the combination of each accumulation of Putaohua Reservoir in Xingnan area of Daqing Placanticline, analyzing the controlling factors of hydrocarbon accumulation, accumulation rule and the corresponding exploration ideas, Enriching and developing the study of non-structural reservoir in slopes and depressions of Daqing Placanticline. The study shows that faults are well-developed, especially oil source faults which were active during the crucial moment of hydrocarbon accumulation, as for connecting source rock and reservoir and poor sealing capacity, they are the main passage for hydrocarbon migration. The relations between oil source faults and reservoir greatly restrict the distribution and scale of reservoirs. Accurate evaluation of the relationship between faults and reservoirs has an important significance which can give a guide to the surrounding exploration of Daqing oilfield and improve the success rate of exploration.
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Womer, M. B. "HYDROCARBON OCCURRENCE AND DIAGENETIC HISTORY WITHIN PROTEROZOIC SEDIMENTS, McARTHUR RIVER AREA, NORTHERN TERRITORY, AUSTRALIA". APPEA Journal 26, n. 1 (1986): 363. http://dx.doi.org/10.1071/aj85031.
Testo completoAbstract (sommario):
The stratigraphy of the Proterozoic in the McArthur River area of Northern Territory consists of the basal, non-economic Tawallah Group, overlain unconformably by dolomitic carbonates and clastics of the McArthur Group, in turn overlain disconformably by Roper Group clastics. Several shows of tarry to brittle bitumen have been reported in sandstones of the Roper Group and in dolomites of the McArthur Group.In thin sections, the bitumen commonly displays shrinkage cracks, apparently associated with the loss of volatiles. Secondary minerals are observed infilling some of the cracks, indicating those phases of diagenesis which occurred subsequent to breaching of the hydrocarbon bearing reservoir. Additionally, the contact relationships of bitumen with the secondary minerals indicate a relatively early migration of hydrocarbons into the reservoir rocks.The inferred sequence for the McArthur Group dolomites is: early dolomitization and silicification, formation of vuggy (vadose) porosity, authigenic deposition of chalcedony at shallow burial depth, cementation by quartz at deep burial depth, migration of hydrocarbons (contemporaneous with sulphide formation), breaching of the reservoir, degradation of hydrocarbons, and deposition of sparry dolomite cement. The inferred sequence of diagenesis for Roper Group clastic reservoirs in this area is: authigenic deposition of minor quartz and illite cement, migration of hydrocarbon, breaching of the reservoir, major authigenic deposition of quartz and illite, degradation of hydrocarbon, and cementation by dolomite, hematite, and kaolinite.
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Fashagba, Imoleayo, Pius Enikanselu, Ademola Lanisa e Olabode Matthew. "Seismic reflection pattern and attribute analysis as a tool for defining reservoir architecture in ‘SABALO’ field, deepwater Niger Delta". Journal of Petroleum Exploration and Production Technology 10, n. 3 (27 novembre 2019): 991–1008. http://dx.doi.org/10.1007/s13202-019-00807-1.
Testo completoAbstract (sommario):
AbstractAn accurate definition of environment of sediment deposition is a sine qua non for characterizing and providing measures for enhancing hydrocarbon reservoirs. Consequently, this study is aimed at determining the sub-environment of deposition and architecture of two reservoirs: S1000 and S2000 reservoirs, in ‘SABALO’ field, deep offshore Niger Delta. In addition, the study is imperative in order to assess reservoir properties such as: geometry, connectivity and continuity, which are important for exploration and reservoir management. In this study, we integrated well logs from six (6) wells and 3D-seismic data (near and far angle stack) for seismic stratigraphic studies. Four major seismic sequences with their corresponding facies units were recognized by analysis of reflection terminations, seismic parameters and external geometry. The reservoirs of interest are within the seismic sequence one containing facies units: SF1A and SF1B. Both reservoirs were delineated to be structurally and stratigraphically controlled. This implies a combinational trapping system at the reservoir level. Also, hydrocarbons in the reservoir were confirmed to be down to reservoir base. Integrated study of the seismic and well logs shows that the two identified reservoirs, S1000 and S2000, were defined to be weakly confined channel complex with an area of 50 km2 and 78 km2, respectively. Their connectivity was defined to be loosely amalgamated and highly amalgamated, respectively. The results of this paper are essential to develop the reservoirs by utilizing the information of their geometry, connectivity and continuity.
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Sarkheil, Hamid, Hossein Hassani e Firuz Alinia. "Fractured reservoir distribution characterization using folding mechanism analysis and patterns recognition in the Tabnak hydrocarbon reservoir anticline". Journal of Petroleum Exploration and Production Technology 11, n. 6 (giugno 2021): 2425–33. http://dx.doi.org/10.1007/s13202-021-01225-y.
Testo completoAbstract (sommario):
AbstractNaturally, fractured reservoirs play a considerable part in the study, production, and development of hydrocarbon fields because most hydrocarbon reservoirs in the Zagros Basin are naturally fractured. Production from those reservoirs is usually affected by the presence of a system of connected fractures. In this study, the Tabnak hydrocarbon field on the fold–thrust belt at the Zagros zone in the Persian plate has been analyzed by the facies models, folding mechanism analysis to identify fracture reservoir patterns. The results show a flexural fold with similarity in the folding mechanism and some open fracture potential made by limestone, shale, clay, and anhydrite in the study area's facies models. Consequently, the stress pattern and type of fracture issue on the fold's upper and lower layers will be similar. On the Tabnak anticline reservoir using image processing techniques in MATLAB R2019 software and kriging geostatistical methods, fracture surface patterns as a block model extended to the depth. Using the model results, fractures’ orientation distribution in adjacent wells 11, 14, and 15 is appropriate. The results also have similarities with the facies models, folding mechanism assessment, well test, and mud loss data analysis. These results can affect the development plans’ primary approach by drilling horizontal and sleep wells and hydrocarbon reservoir management strategies.
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Yang, Runze, Xianzheng Zhao, Changyi Zhao, Xiugang Pu, Haitao Liu, Hongjun Li, Lixin Fu e Ying Tang. "Hydrocarbon Charging and Accumulation in the Permian Reservoirs of the Wumaying Buried Hill, Huanghua Depression, Bohai Bay Basin, China". Energies 14, n. 23 (3 dicembre 2021): 8109. http://dx.doi.org/10.3390/en14238109.
Testo completoAbstract (sommario):
The Wumaying buried hill experienced multi-stage tectonic movements, which resulted in a complicated and unclear nature of the hydrocarbon accumulation process. To solve these problems, in this study—based on the structural evolution and burial–thermal history of the strata, using petrology, fluid inclusion microthermometry, geochemical analysis of oil and gas, Laser Raman spectrum, and fluorescence spectrum—the history of hydrocarbon charging was revealed, and the differences in hydrocarbon charging of different wells was clarified. The results indicate that the only source for Permian oil and gas reservoirs are Carboniferous–Permian coal-measure source rocks in the Wumaying buried hill. There are three periods of hydrocarbon charging. Under the channeling of faults and micro cracks, low-mature oil and gas accumulation was formed in the first period, and the accumulation time was 112–93 Ma. In the late Cretaceous, a large-scale uplift exposed and damaged the reservoirs, and part of the petroleum was converted into bitumen. In the middle–late Paleogene, the subsidence of strata caused the coal-measure to expel mature oil and gas, and the accumulation time of mature oil and gas was 34–24 Ma. Since the Neogene, natural gas and high-mature oil have been expelled due to the large subsidence entering the reservoir under the channeling of active faults; the accumulation time was 11–0 Ma. The microfractures of Permian reservoirs in the Wumaying buried hill are the main storage spaces of hydrocarbons, and the fractured reservoirs should be explored in the future. The first period of charging was too small and the second period was large enough in the WS1 well, resulting in only a late period of charging in this well.
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Alao, P. A., S. O. Olabode e S. A. Opeloye. "Integration of Seismic and Petrophysics to Characterize Reservoirs in “ALA” Oil Field, Niger Delta". Scientific World Journal 2013 (2013): 1–15. http://dx.doi.org/10.1155/2013/421720.
Testo completoAbstract (sommario):
In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential) reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on “ALA” field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of −2,453 to −3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.
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Rile, E. B., A. V. Ershov e A. V. Ershov. "Middle devonian-lower frasnian natural hydrocarbon reservoirs of the Pechora Sea shelf and Timan-Pechora oil and gas province adjacent area". SOCAR Proceedings, SI2 (30 dicembre 2021): 16–25. http://dx.doi.org/10.5510/ogp2021si200539.
Testo completoAbstract (sommario):
The research is based on the three-layer natural hydrocarbon reservoirs theory, which allocates 3 layers in a natural reservoir – the genuine seal, the productive part and the intermediate layer situated between them - the false seal. The Middle Ordovician-Lower Frasnian terrigenous complex variable in thickness, composition and stratigraphic completeness sub-regional natural reservoir was identified in the northern part of the Timan-Pechora oil and gas province adjacent to the Pechora Sea. It includes several zonal and local natural reservoirs (Middle Ordovician-Lower Devonian, Middle Ordovician-Eiffelian, Zhivetian-Lower Frasnian and others). The distribution areas of these natural reservoirs were extrapolated to the Pechora Sea offshore. The areas with the highest prospects of oil and gas potential of the Pechora Sea offshore were delineated, basing on the Timan-Pechora oil and gas potential analysis. These are the northwest extensions into the Pechora Sea of the Denisov trough, the Kolva megaswell, as well as the Varandei-Adzva structural zone and the Karotaiha depression. Keywords: natural reservoir; genuine seal; false seal; field; pool; hydrocarbons.
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Song, Jinmin, Shugen Liu, Hairuo Qing, Luba Jansa, Zhiwu Li, Ping Luo, Di Yang, Wei Sun, Hanlin Peng e Tong Lin. "The depositional evolution, reservoir characteristics, and controlling factors of microbial carbonates of Dengying Formation in upper Neoprotozoic, Sichuan Basin, Southwest China". Energy Exploration & Exploitation 36, n. 4 (9 dicembre 2017): 591–619. http://dx.doi.org/10.1177/0144598717743995.
Testo completoAbstract (sommario):
The Dengying Formation of Neoprotozoic age deposited in north Sichuan Basin, China, is dominated by dolomitic strata containing microbial carbonates. Thirteen cyanobacteria forms, one oncolite and two stromatolitic structures have been identified. Different microfacies may be related to different microbe forms or assemblages as well as depositional environments. Potential hydrocarbon reservoirs in microbial carbonates are of low porosity and permeability. Microbialites develop in the members Z2 dn1, Z2 dn2, and Z2 dn4. The member Z2 dn1 and Z2 dn2 lying in the lower part, dominated by thrombolitic and spongiostromata dolostone, with three reservoir intervals of overall 190 m thick. Laminite and stromatolitic dolostone are the most important in member Z2 dn4, with three reservoir intervals of 119 m thick. Microbial carbonate reservoirs in members Z2 dn1 and Z2 dn2 were effected by two stages of fresh water dissolution, three stages of burial dissolution, and one stage of hydrocarbon invasion. But one stage of fresh water dissolution, two stages of burial dissolution, and three stages of hydrocarbon invasion modified the reservoirs of member Z2 dn4. The dominant factors for microbial reservoirs were microbial textures and development of Mianyang-Changning intracratonic sag.