石油实验地质

2016, 38(6): .

Abstract(389) PDF-CN(1506)

Abstract:

Differential characteristics of large-scale basin evolution and hydrocarbon response of clastic strata in central-western China

Fang Chengming, Huang Zeguang

2016, 38(6): 703-712. doi: 10.11781/sysydz201606703

Abstract(807) PDF-CN(349)

Abstract:
Taking the petroleum accumulation system of clastic strata as the core, and the large-scale basins in the central-western China (Sichuan, Ordos, Junggar and Tarim) as a unified space-time system, we discussed the formation and distribution of accumulation systems and their petroleum response under the control of the superposition of basins since the Late Paleozoic. The formation and distribution of main hydrocarbon source rock strata, self-sourced and self-and-near-sourced petroleum accumulation systems were constrained by the differential structure of prototype compaction during a tectonic transition period. The self-and-far-sourced, externally sourced and hybrid-sourced petroleum accumulation systems were controlled by the tectonic deformation caused by basin superposition. The superposition of intercontinental systems in the Mesozoic to Cenozoic controlled petroleum behavior in different accumulation systems. First, differential tectonic subsidence which generated by foredeep overlap during a tectonic transition period controlled the formation of large lithologic hydrocarbon reservoirs and relative enrichment near tectonic uplift/slope zones in self-and-near-sourced petroleum accumulation systems. Second, the late Yanshanian uplift tilting made the early near-sourcing hydrocarbon reservoirs adjust or dilute. Finally, fault activities ever since the Yanshanian controlled the partial enrichment and high-yielding of hydrocarbon in self-sourced petroleum accumulation systems, and the formation of self-and-far-sourced and externally sourced petroleum accumulation systems. The self-and-near-sourced and self-sourced petroleum accumulations in the Yanshanian uplift or slope are the main hydrocarbon exploration targets in clastic strata in the central basin. In the western basin, we should focus on the externally-sourced and self-and-far-sourced petroleum accumulation systems on the compression-wrench fault belts of active uplifts.

Marine basin reformations and accumulation factors in Lower Yangtze region

Luo Kaiping, Huang Zeguang, Lü Junxiang, Peng Jinning, Lu Yongde, Zhou Lingfang

2016, 38(6): 713-720. doi: 10.11781/sysydz201606713

Abstract(732) PDF-CN(228)

Abstract:
The Paleozoic marine basins in the Lower Yangtze region have experienced 3 stages of tectonic movements since the late Mesozoic including face-to-face compression from the late Indosinian to the early Yan-shanian, sinistral strike slip from the middle to the late Yanshanian, and detachment during the Himalayan period, which made the occurrence and geologic structure of marine basins very complicated. In accordance with the tectonic movements, hydrocarbon generation and accumulation in the marine basins in the Lower Yangtze region also went through 3 periods including initial hydrocarbon generation and early accumulation from Caledonian to the early Indosinian, destruction and adjustment from the late Indosinian to Yanshanian, and secondary hydrocarbon generation and late accumulation during the early Himalayan period. Studies of the Huangqiao, Jurong and Taishan areas show that the current oil and gas pools mainly formed during the late accumulation period. Marine basin occurrence and their geologic structure, effective hydrocarbon source and preservation conditions are key factors for the late accumulation of hydrocarbon.

Petroleum accumulation rules in hysterogenetic reconstructive-syngenetic rift basins, North Jiangsu Basin

Liu Yurui

2016, 38(6): 721-731. doi: 10.11781/sysydz201606721

Abstract(1628) PDF-CN(266)

Abstract:
There are different points of view about the type of North Jiangsu Basin, which affects the understanding of petroleum accumulation. According to the ideas and indicators of an eogenetic morphologic basin, hysterogenetic reconstructive basin and syngenetic rift basin, the North Jiangsu Basin was a hysterogenetic reconstructive-syngenetic rift basin which developed from a great depression during the Taizhou and Funing periods, and changed to a syngenetic rift basin of dustpan shape after strong deformation. Subsequently, the syngenetic rift basin and fading depression superimposed during the Dainan-Sanduo and Yancheng-Dongtai periods, respectively, finally forming a syngenetic-hysterogenetic rift basin. Based on geochemical theory and experimental data, and taking into consideration the fact that no success has been made in the exploration for immature oils in the past 30 years, we believe that hydrocarbon in the study area mainly developed from kerogen during the late stage, and hydrocarbon maturity and the kitchen distribution varied among areas. An early immature and low-maturity hydrocarbon generation zone, double-peak mode hydrocarbon generation, immature and low-maturity oils do not exist. Source rocks in the basin have a low abundance of organic matter. Effective mature source rocks which can provide enough hydrocarbon and multiple roles of faults are the key controls for hydrocarbon accumulation. Oil and gas migrated mainly in a lateral direction, and re-servoirs distributed of fan shape along half-graben hydrocarbon kitchens in the hysterogenetic reconstructive basin. Petroleum migrated mainly in the vertical direction, structural pools lay above hydrocarbon kitchens like bead strings, and structural-lithologic oil pools superimposed and distributed on the rim of syngenetic rift basin. Petroleum accumulations are discontinuous throughout the whole basin.

Adsorption capacity and controlling mechanisms of Paleozoic shales in Yangtze region

Xu Liangwei, Liu Luofu, Liu Zufa, Meng Zhaoping

2016, 38(6): 732-741. doi: 10.11781/sysydz201606732

Abstract(776) PDF-CN(309)

Abstract:
As a gas-rich shale layer, the Paleozoic in Yangtze region is a main target for shale gas exploration and development in China. Adsorption state is one of the most important occurrence modes of shale gas; hence it is very necessary to study the adsorption capacity and controlling mechanisms of shales. We collected some shale samples from Paleozoic in Yangtze area, and then carried out TOC analysis, Rock-Eval, XRD and water content analyses, isothermal adsorption experiments, and ultra-high pressure isothermal adsorption experiments. The adsorption properties of shales vary during different ages and in different areas due to the combined effects of TOC content and mineral composition. The TOC content and methane adsorption of shales do not have a positive relationship as proposed by previous researchers, because that shale samples are limited and are in the high-mature and over-mature stages. The methane adsorption isotherms of kerogens in different ages show that older kerogens have a stronger methane adsorption capacity. Removing the effects of organic matter abundance and maturity, the kerogens of type Ⅲ adsorb more methane than those of type Ⅱ. If organic matter abundance and type are the same, the methane adsorption amount of high maturity kerogen is more than that of low maturity kerogen. Soluble organic matter can dissolve and adsorb methane, and hence improve the methane adsorption capacity of shales. The relationship between clay mineral and methane adsorption which is normalized by TOC is not obvious, this is mainly because the samples contain water. Maturity, porosity and permeability may affect the maximum methane adsorption of shales. Compared with low pressure, the methane adsorption characteristics under high pressure have a certain continuity. There are several influencing factors, which demand deep research to reveal the influence of each single factor on shale adsorption characteristics.

Differences of fracture characteristics and the influence on productivity in the northeastern Sichuan continental basin

Li Jingrong, Zhu Hua, Fen Xiaoming, Cheng Hongliang, Yan Xiao

2016, 38(6): 742-747. doi: 10.11781/sysydz201606742

Abstract(821) PDF-CN(378)

Abstract:
Reservoirs in the northeastern Sichuan continental basin are all tight reservoirs. However, fracture cha-racteristics and their influence on productivity are different among various areas and formations. Comparisons were made based on core, thin section, logging, gas testing and producing data collected from the eastern Yuanba, western Yuanba and Malubei blocks. The eastern and western Yuanba blocks mainly developed shearing fractures with low angle and low density. Fractures in the eastern Yuanba block are more effective than those in the western Yuanba block. The Malubei block developed both shearing and extensive fractures of mechanical geneses, with high angle, density and permeability. The angle, effectiveness and density of macro fractures controlled the productivity of gas wells. A dense micro fracture network or micro fracture dissolution improves the reservoir matrix and determined if a gas well had a stable production.

Characteristics of natural fractures and their influence on dynamic gas and water distribution in Xinchang gas field

Wang Dandan, Li Hao, Zhao Xiangyuan, Ji Mingyan

2016, 38(6): 748-756. doi: 10.11781/sysydz201606748

Abstract(826) PDF-CN(322)

Abstract:
The characteristics of natural fractures in the second member of Xujiahe Formation in Xinchang gas field were studied using core, logging and production data. The responses of natural fractures of different types were determined using conventional logging data, by which we evaluated the influence of various fracture types on dynamic gas and water distribution, and discussed their geologic origin. Tectonic and diagenetic fractures are predominant in the Xujiahe reservoirs in Xinchang gas field. Most of the tectonic fractures are shear fractures, which can be classified into high angle, oblique and low angle fractures according to their inclination angles. The diagenetic fractures are mainly bedding fractures with a good effectiveness, and contribute greatly to reservoir physical properties. The dynamic gas and water distribution and fracture development in the study area were closely related to the development degree and type of fractures. The reservoirs which mainly develop low angle fractures (especially bedding fractures) or network fractures produce water or meet high water cut rapidly, while reservoirs with high angle fractures show a high and stable gas yield rate. Permeability anisotropy caused by natural fractures of different types controlled the dynamic gas and water distribution in the study area.

Main controls on the distribution of the 3rd member of Liushagang Formation in eastern Wushi Sag, Beibu Gulf Basin

Zeng Xiaoming, Zou Mingsheng, Zhang Hui, Yu Jia, Chen Xiaowu, Mo Fengyang

2016, 38(6): 757-764. doi: 10.11781/sysydz201606757

Abstract(968) PDF-CN(471)

Abstract:
Fan delta reservoirs in the 3rd member of Liushagang Formation in the eastern Wushi Sag, Beibu Gulf Basin are characterized by large thickness of sand bodies, complicated lithology, rapid change of physical properties, and unclear distribution of good-quality reservoirs, which restricts further development. The controls of the sedimentary environment, diagenesis and structure on reservoir physical properties were studied using drilling, logging and testing data. Shale content, sorting and psephicity have a huge influence on physical properties. Compaction and dissolution controlled later reservoir porosity evolution. Paleotectonics and fracture systems controlled acid fluid migration direction and path. Underwater distributary channels of the proximal outer fan delta front near the large fault which exhibited low matrix content, good sorting and psephicity, good physical properties, high productivity and were good-quality reservoirs in the study area.

Differential tectonic deformation and dynamic processes in Caohu area, northeastern Tarim Basin

Tian Mi, Zhao Yongqiang, Luo Yu, Ma Yuchun, Zhou Yushuang, Zhang Genfa

2016, 38(6): 765-771. doi: 10.11781/sysydz201606765

Abstract(812) PDF-CN(337)

Abstract:
The Caohu area located in the northeastern Tarim Basin closed against the Kuluktag Lift. Paleozoic and Mesozoic strata were preserved very well, which recorded the tectonic evolution of the northeastern Tarim Basin. Based on the interpretation of the latest 2D seismic data and the theory of fault-related folding, this paper analyzed the geometrical and kinetic features of deformations in the Caohu area. Faulting deformations in the Caohu area have the characteristics of vertical stratification, S-N segmentation, and E-W zonation. Thrusts and thrust-strike slip faults were dominant. Tectonic deformation took place mainly in the late Hercynian, Indosinian and middle Yanshanian, and had the geometrical features of fault-related folds. Structural evolution history was recovered using an equilibrium profile technique. The late Caledonian to early Hercynian movements controlled the main upwarped and downwarped structural framework in the Caohu area, developing the Akekule Arch, Caohu Sag and Yuli Nose Arch. Thrust detachment faults developed during the late Hercynian, and experienced two phases of thrust-strike slip reform in the Indosinian and Yanshanian epochs, resulting in the present tectonic pattern of the study area.

Mineral and genesis study of authigenic aragonite in sucrosic dolomites from Middle Jurassic Buqu Formation in southern Qiangtang Basin, Tibet

Zhang Shuai, Yi Haisheng, Xia Guoqing, Liang Dingyong

2016, 38(6): 772-778. doi: 10.11781/sysydz201606772

Abstract(1189) PDF-CN(304)

Abstract:
Columnar-acicular cement has been discovered in the Middle Jurassic Buqu Formation of Longeni area in the southern Qiangtang Basin of Tibet, distributed in saccharoidal dolomite in dissolution pores filled with bitumen. As demonstrated by microstructure, in situ X-ray diffraction (XRD) and electron microprobe analysis (EMPA), mineralogical investigations have confirmed the emergence of authigenic aragonite. It occurs as bundles and radiating clusters consisting of needle crystals. Major elements show that MgO and SrO have a positive correlation. In situ isotopic analysis indicates that δ¹³C values range from 3.5‰PDB to 3.98‰PDB and δ¹⁸O ranges from -9.98‰PDB to -11.63‰PDB. Aragonite is rarely found in carbonate rocks formed during geological times because of the conversion of aragonite to low-Mg-calcite through neomorphism or dissolution. Oxygen and carbon isotopic composition of aragonite cements in saccharoidal dolomite has greater variability compared with aragonite formed in modern marine or meteoric diagenesis. In the formation process meteoric water leaching has less influence and a negative excursion of δ¹⁸O is mainly controlled by geothermal gradient during burial. The reservoir diagenetic sequence shows that aragonite cements formed after burial dolomitization. Authigenic mineral precipitates with organic acid dissolution, and hydrocarbon filling has largely inhibited the conversion of aragonite to calcite. The comprehensive analysis suggests that aragonite cements were precipitated from a dissolution-reprecipitation process of carbonate minerals during late diagenesis. Hydrocarbon filling played an important role controlling the preservation of aragonite cements.

Main controlling factors for carbonate rock distribution on the southern slope of Chezhen Sag, Bohai Bay Basin

Lin Hongmei

2016, 38(6): 779-786. doi: 10.11781/sysydz201606779

Abstract(825) PDF-CN(254)

Abstract:
The distribution of carbonate rocks on the southern slope of Chezhen Sag in Bohai Bay Basin was stu-died using well logging, drilling and testing data. Carbonate rocks mainly distribute in the upper section of the fourth member of Shahejie Formation, including micrite limestones, biolithite limestones, argillaceous limestones and dolomites. The study area had a landscape pattern of "two subsags and one uplift in the middle" during the deposition of the upper section of the fourth member of Shahejie Formation, which determined the distribution and thickness of carbonate rocks. The study area belonged to shore-shallow lake environment. Carbonate rocks developed at about 11-50 m depth, and most developed at 34 m. From the early to the late period of the deposition of the upper section of the fourth member of Shahejie Formation, paleoclimate changed from dry to humid, and the distribution range of gypsum rocks gradually narrowed while that of carbonate rocks expanded. With the combined function of ancient landscape,water depth and paleoclimate, clastic rocks, argillaceous limestones, biolimestones, micrites, dolomites, gypsum-salt rocks, argillaceous limestones and calcareous rocks were depo-sited from basin edge to center. A sedimentary model for the deposition of carbonate rocks was established.

Development and controlling factors of Neogene reefs in Xisha sea area

Yang Zhen, Zhang Guangxue, Zhang Li, Xia Bin

2016, 38(6): 787-795. doi: 10.11781/sysydz201606787

Abstract(975) PDF-CN(322)

Abstract:
During the Neogene a large number of reefs developed in the Xisha sea area with a great potential for oil and gas exploration. High-resolution seismic data and extensive well drilling data provided an opportunity to understand the evolution of reefs in this area. A few reefs initially developed on a basement high in the early Miocene. In the early Middle Miocene, the reefs, such as point reefs, platform-edge reefs, and pinnacle reefs, flourished on the western slope of Xisha Uplift. They gradually back stepped to the elevated topographic highs in response to a relative sea level rise. In the late Middle Miocene, reefs began to wither and mainly grew on the Xisha Uplift represented by horse toe reefs and platform-edge reefs. Since the Late Miocene, many reefs formerly developing on the edge of the Xisha Uplift were submerged and only some atolls survived around the islands on the Xisha Uplift. Tectonics and eustasy controlled the development of Neogene reefs in the Xisha sea area. Tectonics controlled the topography for the initial growth of reefs, and tectonic subsidence combined with rapid relative sea-level changes controlled reef evolution during the Neogene. In addition, the rhythm of relative sea-level changes in a short time also influenced the sedimentary cycles of reefs.

Sequence stratigraphic research of volcanic and clastic sediment basins: A case study of Changling Fault Depression in Songliao Basin

Wang Miao, Lu Jianlin, Zuo Zongxin, Wang Baohua, Li Hao, Zhang Yanxia

2016, 38(6): 796-802. doi: 10.11781/sysydz201606796

Abstract(1297) PDF-CN(258)

Abstract:
The Early Cretaceous is complicated and hard to compare since it was influenced by multiple tectonic movements and volcanism. In order to resolve the problems mentioned above, we studied stratum structure and sequence stratigraphy based on freshly obtained outcrop, core, well logs, seismic and dating data, using basic principles of sequence stratigraphy and sedimentology. The kinetic mechanism and volcanism in this area were also considered in the research. Some identification methods for dual-structure basins with "volcanic rocks and sedimentary rocks" were put forward, and the stratigraphic sequence framework of the Early Cretaceous in the Changling Fault Depression was set up. Three sequence patterns were proposed:volcanic fault lake sequence, gentle slope composed of "volcanic and sedimentary rocks" in a dual structure sequence, and "volcanic and sedimentary rocks" constitute straticulate (finely laminated) sequence. These sequence patterns have a guiding significance for identifying source, reservoir and cap rock assemblages.

Formation conditions of deep hydrocarbon in Junggar Basin, NW China

Bai Hua, Pang Xiongqi, Kuang Lichun, Pang Hong, Pang Ying, Zhou Liming

2016, 38(6): 803-810. doi: 10.11781/sysydz201606803

Abstract(1244) PDF-CN(338)

Abstract:
With the increasing degree of identified shallow hydrocarbon resources, the possibility of making a breakthrough in shallow strata is decreasing and the direction of oil and gas exploration is turning to deep strata. All around the world, over one thousand hydrocarbon reservoirs have been discovered and developed in deep strata with buried depth greater than 4 500 m. At present, the depth of all the discovered and developed hydrocarbon reservoirs is less than 4 500 m in the Junggar Basin. Considering that a breakthrough has not yet been made in deep strata, a discussion of deep hydrocarbon accumulation conditions has important practical significance in the Junggar Basin. Based on previous studies, source rocks, reservoirs, cap rocks and preservation conditions are taken as research subjects and the accumulation conditions of deep hydrocarbon are analyzed. The southern margin and central depression of the basin developed many sets of argillaceous source rocks in the deep zone and have entered into the mature to high-maturity stage. Due to the geological processes of over-pressure and erosion, etc., relatively high-quality reservoir intervals are widely developed in deep strata. Many regional cap rocks can be effective seals, beneficial to deep oil and gas accumulation and preservation. Timing and spatial relationships among source rocks, reservoirs, cap rocks, and the hydrocarbon shows in deep strata of exploration wells suggest that the central depression and southern margin are favorable zones for deep oil and gas exploration.

Controlling effect of normal drag structure on the internal reservoir architecture in an alluvial fan

Yin Senlin, Wu Shenghe, Hu Zhangming, Wu Xiaojun, Chen Yanhui, Ren Xiang

2016, 38(6): 811-820. doi: 10.11781/sysydz201606811

Abstract(1137) PDF-CN(301)

Abstract:
The coupling relationship between the normal drag structure developed in the hanging wall of a contemporaneous reverse fault and the internal reservoir architecture in alluvial fan, based on core, outcrop, dense well and seismic data is unclear. Well-to-seismic calibration, elevation differences between key and target strata, hierarchy bounding surface analysis and comprehensive geological analysis have been used to clarify this relationship. The differential distribution characteristics of internal reservoir architecture under the control of normal drag structure were studied. Research shows:(1) Normal drag structure has 4 essential features:asymmetrical anticline uplift morphology, uplifted extent difference exists in different places with cumulative effect, extensional tectonic and unconformities often appear, successive development and distribution range gradually change. (2) The bed form of differential uplifting caused by normal drag structure controlled the dispersion and filling with sandy conglomerate, which was different from the traditional mode, that is, different architecture may appear at the same distance to the fan root. (3) Normal drag structure controlled sediment accommodation space. Uplift made the space decrease, and on the wings increase instead. On the other hand, uplifting sedimentary bed form affected the direction of paleocurrent and changed the distribution of internal architecture in an alluvial fan reservoir. Architecture element type and scale no longer changed along the radial direction.

Petroleum geology characteristics and exploration directions in Espirito Santo Basin, Brazil

Xie Huafeng, Zhou Shengyou, Hui Guanzhou

2016, 38(6): 821-827. doi: 10.11781/sysydz201606821

Abstract(1276) PDF-CN(203)

Abstract:
In recent years, a great discovery of petroleum has been made in the Santos and Campos basins; however, little has been made in the Espirito Santo Basin which is adjacent to the two basins. Exploration level of the basin is also low. We studied the sedimentary characteristics, tectonic evolution, source rock, trap and reservoir in detail, and found the petroleum distribution rules, main factors and modes of petroleum accumulation, in order to reveal petroleum enrichment regularity and point out exploration directions in the Espirito Santo Basin. The basin belongs to the passive continental margin basin group near the east coast of Brazil, successively experiencing rifting, transitional and drifting periods, and accordingly developing sub-salt, salt and supra-salt rock sequences. Influenced by the salt diapirism, the basin has formed a very different sub-salt and supra-salt double-layer structure, within which the sub-salt structure shows a propensity for "oblique board" zoning in general under the control of a rift system and the supra-salt structure, controlled by a gravity slide system, has developed various types of salt structure. The Aptian stage Cricare group Neocomian lacustrine shale is the best hydrocarbon source rock and petroleum is mainly distributed in the Upper Cretaceous-Neogene supra-salt turbidite sand, dominated by lithologic traps. The analysis shows that distribution of turbidite sand and migration pathways are the main controlling factors of petroleum accumulation, and the basin has 6 exploration directions at present, among which the near shore slope area is the most favorable for petroleum migration and accumulation.

Differences and controls of carbon and oxygen isotope composition in dolomite and coexisting calcite under deposition conditions

Li Xiaoning, Huang Sijing, Huang Keke, Zhong Yijiang, Hu Zuowei

2016, 38(6): 828-835. doi: 10.11781/sysydz201606828

Abstract(1164) PDF-CN(242)

Abstract:
We discussed the composition and factors influencing carbon and oxygen isotopes in dolomites and coexisting calcites in hand specimen mesoscale based on petrography and combined with elemental, X-ray diffraction and carbon and oxygen isotope analyses. Results indicated that dolomites have higher δ¹³C and δ¹⁸O values than coexisting calcites. Two factors may account for the higher δ¹⁸O values of dolomites. (1) The oxygen isotope fractionation factors of a dolomite-water system are higher than those of a calcite-water system. Therefore, oxygen isotope fractionation factors are greater than 1 in a dolomite-calcite system. (2) The fluids of dolomite precipitation have higher salinity and higher ¹⁸O abundance compared to coexisting calcite. In addition, the δ¹³C values of dolomites show the same trends with δ¹⁸O values. That is to say, the carbon isotope fractionation factors in a dolomite-CO₂ system are higher than those in a calcite-CO₂ system. Therefore, carbon isotope fractionation factors are greater than 1 in a dolomite-calcite system during replacement process. Oxygen isotope values varied obviously between syndepositional dolomites and coexisting calcites, while they were similar between hydrothermal/deeply burial dolomites and coexisting calcites.

Experimental analysis of aquathermal pressuring under high temperature conditions and its geological implications

Guo Zhifeng, Liu Zhen, Liu Peng, Liu Wanchun

2016, 38(6): 836-841. doi: 10.11781/sysydz201606836

Abstract(941) PDF-CN(408)

Abstract:
Overpressure generation mechanism is very important for the research of hydrocarbon accumulation. We collected samples from typical wells in high temperature basins, made use of a double-axial pressurization testing system for pore fluid aquathermal pressuring, and measured the amplitude of aquathermal pressuring for different geological conditions. Results indicated that the relationship between temperature and pressure was not linear but exponential on the condition of high aquathermal pressuring in shale sealed systems, while the amplitude of aquathermal pressuring in isolated systems was higher than that in shale sealed systems. The fine variation of properties of sealed shales would lead to a large amplitude of aquathermal pressuring in shale sealed systems, and the greater porosity of sand samples would lead to larger amplitude of aquathermal pressuring. Experimental results induced two geological implications. In high temperature basins, aquathermal pressuring in shale sealed systems increases significantly with burial depth. It cannot be neglected and could be one of the main overpressure generation mechanisms. The quality of sealed shale decides the amplitude of aquathermal pressuring, and sand porosity could affect the amplitude of aquathermal pressuring, so in geological conditions, high porosity sand embedded in low porosity shale layers is more likely to lead to aquathermal pressuring.

Quantitative characterization of shale oil in different occurrence states and its application

Jiang Qigui, Li Maowen, Qian Menhui, Li Zhiming, Li Zheng, Huang Zhenkai, Zhang Caimin, Ma Yuanyuan

2016, 38(6): 842-849. doi: 10.11781/sysydz201606842

Abstract(2406) PDF-CN(608)

Abstract:
Crude oils in shale systems exist in different modes, where only free oil could be a potential contributor to shale oil production. However, there is a general lack of analytical methods for quantitative characterization of free and adsorbed oils in organic-rich shale, and little is known of the interrelationships among different states of oils and porous media in shale. A modified Rock-Eval and pyrolysis-gas chromatographic method was established to quantify different modes of shale oil occurrence in various geological samples. In combination with solvent extraction, this technique was applied to analyze continuous shale core samples collected from exploration wells in the Jiyang Depression, Bohai Bay Basin, East China. The results showed a positive correlation between adsorbed oil content and total organic carbon abundance, and a pronounced decrease in the kerogen miscible oil content with increasing thermal maturity. On the other hand, the free/adsorbed oil ratio decreases with increasing TOC in a shale system, suggesting that free oil is associated mainly with inorganic mineral matrix and/or fractures. The study provides a rapid technique for the characterization of shale oil occurrence and the quantitative evaluation of shale oil resources.

Influence of bulk volume measurement on porosity error in tight reservoir core plug analysis

Chen Siyu, Tian Hua, Liu Shaobo, Li Caixi, Hao Jiaqing, Zheng Yongping

2016, 38(6): 850-856. doi: 10.11781/sysydz201606850

Abstract(936) PDF-CN(284)

Abstract:
Unconventional tight reservoir has a low porosity, which is usually less than 10%, while that of shale reservoir is even less than 5%. The porosity test error of helium injection method has been considered. A mathema-tical model is established for the error of porosity determination and the statistical data of source and error limit was obtained for volume measurement. (1) The error limit of porosity determination of tight reservoir using vernier caliper is 0.59%-2.47%, while that can be reduced to 0.38%-1.04% by using a high-precision 3D laser scanner. Different from conventional reservoirs, the porosity measurement accuracy of tight reservoir should be improved and analyzed. (2) The accuracy of all porosity determination methods cannot reach the industry standard (<0.5%), so a new standard is suggested that reducing the error limit standard (i.e. <1%). The demand of volume measurement was made based on the new standard. (3) An inverse proportion is found between porosity error and core plug length, so sample length should be longer than 3 cm to reduce porosity error.

2016, 38(6): 857-864.

Abstract(277) PDF-CN(210)

Abstract:

2016 Vol. 38, No. 6

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