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2016 Vol. 38, No. 4

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2016, 38(4): .
Abstract(796) PDF-CN(1036)
Abstract:
Organic matter occurrence and hydrocarbon generation in shale
Xu Xuhui, Zheng Lunju, Ma Zhongliang
2016, 38(4): 423-428. doi: 10.11781/sysydz201604423
Abstract(1114) PDF-CN(1007)
Abstract:
The microscopic features of various shales showed that sedimentary organic matter and minerals mainly exist as an "enriched organic matter and mineral aggregation" or "lean organic matter and mineral matrix". The simulations of hydrocarbon generation and expulsion in shale indicated that the difference of organic matter occurrence in shale controlled hydrocarbon generation and primary migration. Due to the heterogeneous distribution of "enriched organic matter and mineral aggregation", the hydrocarbon generated, expelled and preserved at different stages showed different occurrence and migration features. When maturity ranges from 0.6%-1.0% Ro, oil is free or absorbed in the "enriched organic matter and mineral aggregation". Poor liquidity restricts exploration potential. When Ro ranges from 1.0%-1.3%, it is more favorable for shale oil exploration. The content of "enriched organic matter and mineral aggregation" determined the gas potential in shale during the high evolution stage. In view of the heterogeneity of the microstructure of sedimentary organic matter and inorganic minerals in source rocks, the generation, expulsion and retention of oil and gas should be regarded as a united process when exploring for shale gas.
Composition difference of soluble organic matter in different media in mudstones and its significance for shale oil enrichment
Zhu Jingxiu
2016, 38(4): 429-437. doi: 10.11781/sysydz201604429
Abstract(1542) PDF-CN(1261)
Abstract:
The composition of soluble organic matter in mudstones is complex and the study of composition diffe-rence is not only important to understanding hydrocarbon generation and expulsion processes, but also necessary for us to determine shale oil formation and accumulation mechanisms. Lacustrine shale of the Hetaoyuan Formation in the Biyang Sag of Nanxiang Basin was systematically studied to determine the composition difference of soluble organic matter from different media (including inorganic minerals and kerogen). The results were compared with shale oil and sandstone oil, and their geological and geochemical significance discussed. Results show that, it is mainly because of the similar polarity among various compounds of saturated hydrocarbon that we can hardly distinguish the difference of saturated hydrocarbon component of soluble organic matter in different media, which implies shale oil generation and expulsion processes in source rock. However, there are obvious variations of aromatic composition. The aromatic composition of soluble organic matter in organic medium is similar to shale oil/sandstone oil, but the aromatic composition of soluble organic matter in inorganic medium is different from shale oil/sandstone oil, which reflects the processes of hydrocarbon generation and expulsion. Accordingly, in the primary migration in mudstone, the generated hydrocarbons firstly filled inorganic mineral pores, after achieving the adsorption capacity of mineral particles, then entering into the micro-cracks in source rock and/or sandstone interlayer, finally forming oil and gas enrichment, which was the so-called shale oil.
Shale gas occurrence under burial conditions
Yu Lingjie, Fan Ming, Tenger, Liu Youxiang
2016, 38(4): 438-444. doi: 10.11781/sysydz201604438
Abstract(1676) PDF-CN(1384)
Abstract:
Shale samples were collected from the Longmaxi Formation in southeastern Sichuan Basin to carry out quantitative studies of shale gas occurrence under burial conditions.The impacts of TOC content, temperature and moisture on adsorption capacity were studied using gravimetric isothermal adsorption, and some related empirical equations were established to calculate adsorbed gas content under burial conditions. In addition, free gas storage space was derived by deducting the volume of pore water and adsorbed gas from total space. The density of free gas was calculated using the Peng-Robinson equation. Therefore, a quantitative calculation method for shale gas occurrence was proposed. Under overpressure condition, adsorbed gas content decreases with the increase of burial depth, while free gas content increases and becomes dominant. Shale gas content of well Jiaoye1 was calculated using 22 samples mainly from 38 m interval. The adsorbed gas fraction is 27.1%-47.8% with an average of 34.3%, and the free gas fraction is 52.2%-72.9% with an average of 65.7%.
Main factors controlling shale gas accumulation and exploration targets in the Lower Cambrian, Sichuan Basin and its periphery
Yan Jihong, Li Qigui, Zhu Xiang
2016, 38(4): 445-452. doi: 10.11781/sysydz201604445
Abstract(1799) PDF-CN(1394)
Abstract:
We studied the basic geological conditions and main controlling factors for shale gas accumulations in the Sichuan Basin and its periphery based on the latest theories for shale gas exploration and modeling results. Dark shale deposited in the Lower Cambrian can be defined as passive continental shale and tensional trough shale. The passive continental shale has good quality, great thickness and wide distribution. It has favorable basic conditions for shale accumulation, but the bottom plates are unfavorable and the structural deformation is extensive, thus the preservation conditions for shale gas are unfavorable. Tensional trough shale has reached the standard of basic hydrocarbon rocks, though the thickness of single shale interval is limited. It developed many vertical layers with good top and bottom plates and weak structural deformation. High thermal evolution degree restricted the gas-bearing capacity of dark shale, which was unfavorable for shale gas enrichment. Top and bottom seals are necessary when shale gas reservoirs were formed during the early stage. Tectonic conditions are important for the preservation of shale gas during the late stage. The favorable area for shale gas exploration is Mianyang-Lezhi-Longchang-Changning in the Sichuan Basin, Chengkou-Wuxi in the northeastern Sichuan Basin, Yien-Hefeng in the western Hubei, Huayuan-Zhangjiajie in the western Hunan, and Zhenyuan in Guizhou.
Micro-pore structure and connectivity of the Silurian Longmaxi shales, southeastern Sichuan area
Liu Weixin, Bao Fang, Yu Lingjie, Zhang Wentao, Zhang Qingzheng, Lu Longfei, Fan Ming
2016, 38(4): 453-459. doi: 10.11781/sysydz201604453
Abstract(1282) PDF-CN(1427)
Abstract:
Micro-pore structure and connectivity of the Silurian Longmaxi shales in the southeastern Sichuan Basin were studied using CT, FIB-SEM, Ar+-SEM, and TEM techniques. Four modes for micro-pores in shales were determined to be as follows. (1) Intergranular micro-pores which exist between mineral grains and account for a small proportion of the total. (2) Intragranular micro-pores which mainly exist in intergranular dispersed organic matter or symbiosis organic matter with globular pyrite, and some between clay layers. (3) Grain boundary fractures which exist around organic or mineral grains, and work as a connective network for the shales. (4) Interlayer bedding which provides filtration channels. Intraparticle organic nano-pores are bubble like, show a normal size distribution, and are connected to each other. Their diameter mainly ranges from 30-90 nm and throat width ranges from 7-20 nm. Interlayer bedding accounts for 1%-2% of total shale pores and fractures, and are favorable filtration channels. Micro-pores and fractures in organic matter provide the main reservoir space for shale gas, grain boundary fractures form a connective network, while interlayer bedding provides filtration channels.
Biogenic origin and hydrocarbon significance of siliceous shale from the Wufeng-Longmaxi formations in Fuling area, southeastern Sichuan Basin
Lu Longfei, Qin Jianzhong, Shen Baojian, Tenger, Liu Weixin, Zhang Qingzhen
2016, 38(4): 460-465. doi: 10.11781/sysydz201604460
Abstract(1486) PDF-CN(1393)
Abstract:
Drill core samples were collected from the Fuling area in the southeastern Sichuan Basin to study the origin of siliceous shale rich in organic matter in the Wufeng-Longmaxi formations. X-ray diffraction, optical microscopy, scanning electron microscopy and energy dispersive spectroscopy were applied to study the mineral components, micro-morphology and structure of the samples. Quartz is dominant in the lower part of Wufeng-Longmaxi formations, and decreases gradually upwards, while clay content increases. Abundant biological residue and debris with circled growth structure and needle structure were clearly observed, especially in the Wufeng Formation and the lower part of Longmaxi Formation. The circled structure has a skirt-like boundary, and was filled with microcrystalline quartz. Smaller quartz grains among biological residues are like irregular balls or ellipsoids. They are not idiomorphic, and are authigenic quartz via silica precipitation from siliceous organism dissolution. Debris scattered in mineral matrix, either in complete or clastic form. The enrichment of siliceous organisms and siliceous recrystallization provide direct biogenic evidence for siliceous shale in the Wufeng-Longmaxi formations, which has an important significance for potential hydrocarbon recovery, water sedimentary environment trace, micro-pore and fracture structure, and rock mechanics analysis.
Application of bitumen and graptolite reflectance in the Silurian Longmaxi shale, southeastern Sichuan Basin
Yang Yunfeng
2016, 38(4): 466-472. doi: 10.11781/sysydz201604466
Abstract(1627) PDF-CN(1275)
Abstract:
Graptolites with clear morphology and pore-filling amorphous bitumen are abundant in the Lower Silurian Longmaxi shales from the southeastern Sichuan Basin. It is very necessary to distinguish them exactly for thermal maturity research in this area. Reflectance measurements of the Longmaxi shales from several boreholes have revealed that graptolite reflectance has a better consistency on regional distribution than bitumen reflectance. Graptolite reflectance is more than 3.0%, which is a little bit higher than bitumen reflectance, and gradually increases from southwest to northeast. The equivalent vitrinite reflectance based on graptolite reflectance is more than 2.0%, indicating that the Longmaxi shales from the southeastern Sichuan Basin are over-mature. However, the correlation between graptolite reflectance and equivalent vitrinite reflectance is uncertain yet, and needs further study.
Trapping pressure of fluid inclusions and its significance in shale gas reservoirs, southeastern Sichuan Basin
Xi Binbin, Tenger, Yu Linjie, Jiang Hong, Shen Baojian, Deng Mo
2016, 38(4): 473-479. doi: 10.11781/sysydz201604473
Abstract(1136) PDF-CN(1446)
Abstract:
Facies studies on fluid inclusions revealed that aqueous and gas-bearing inclusions are distributed in quartz and calcite veins of shale gas reservoirs in wells Jiaye A, Nanye A and Pengye A in the southeastern Sichuan Basin. Raman probe analyses showed that gas-bearing inclusions mainly contain CH4. The homogenization temperature of aqueous inclusions ranges from 215.8-245.4 ℃ in quartz veins of well Jiaoye A. The homogenization temperature of aqueous inclusions ranges from 214.4-240.8 ℃ in quartz veins in well Nanye A. The homogenization temperature of aqueous inclusions ranges from 177.8-210.4 ℃ in calcite veins in well Nanye A. The homogenization temperature of aqueous inclusions ranges from 128.5-156.4 ℃ in calcite veins in well Pengye A. The trapping pressure of gas-bearing inclusions and aqueous inclusions ranges from 114.9-130.5 MPa in quartz veins in well Jiaoye A. The trapping pressure of gas-bearing inclusions and aqueous inclusions ranges from 124.0-151.5 MPa in quartz veins in well Nanye A. The trapping pressure of gas-bearing inclusions and aqueous inclusions ranges from 124.0-151.5 MPa in quartz veins in well Nanye A. The trapping pressure of gas-bearing inclusions and aqueous inclusions ranges from 114.0-122.3 MPa in calcite veins in well Nanye A. The trapping pressure of gas-bearing inclusions and aqueous inclusions ranges from 32.5-43.0 MPa in calcite veins in well Pengye A. Fluid inclusions in these wells were trapped during the Yanshanian period. Reservoirs were over pressured when fluid inclusions were trapped in wells Jiaoye A and Nanye A, but under normal conditions in well Pengye A. Pressure coefficients when trapping showed similar regularities as measured well pressure, inferring that the gas preservation conditions in wells Jiaoye A and Nanye A are better than that of Pengye A.
Characteristics and hydrocarbon significance of organic matter in shale from the Jiaoshiba structure, Sichuan Basin: A case study of the Wufeng-Longmaxi formations in well Jiaoye1
Shen Baojian, Yang Yunfeng, Tenger, Qin Jianzhong, Pan Anyang
2016, 38(4): 480-488. doi: 10.11781/sysydz201604480
Abstract(1366) PDF-CN(1559)
Abstract:
Organic-rich shale samples were collected from the Upper Ordovician Wufeng-Longmaxi formations in the Jiaoshiba structure in the Sichuan Basin to carry out rock, kerogen and micro-fossil analyses. The biological recognition and organic petrologic analysis of hydrocarbon generation were carried out, and the hydrocarbon potential was discussed. Hydrocarbon precursor organisms in the high-maturity or over-mature Wufeng-Longmaxi shale mainly included acritarchs, alginite (lamalginite and benthic algae) and zooclasts (graptolite, chitinozoan and spicule), which were the major components of formed organic matter. However, amorphous organic matter was the primary portion in the Wufeng-Longmaxi shale, and was dispersed in the mineral matrix as fined particles. Shale gas in Jiaoshiba area was derived from hydrogen-rich alginite and macromolecular lipid polymer in graptolite tracheids. Abundant amorphous organic matter, especially plenty of pore-filling fine-grained bitumen, indicated that the source rocks have high hydrocarbon potential, which could form large shale gas fields.
Influence of petrological characteristics on fracability of the Paleogene shale, Jiyang Depression
Hao Yunqing, Song Guoqi, Zhou Guangqing, Li Zheng, Wang Weiqing, Li Bo, Zhang Cunxia
2016, 38(4): 489-495. doi: 10.11781/sysydz201604489
Abstract(1454) PDF-CN(1336)
Abstract:
The Paleogene shale is rich in oil and gas in the Jiyang Depression. However, the recent fracturing effect of certain exploration wells was not as successful as expected. The influencing factors for shale fracability were analyzed based on petrological characteristics, such as the occurrence and genesis of brittle minerals, types and relative composition of clay minerals, organic content, diagenesis stage and the development degree of natural fractures. The main brittle minerals in shale from the Jiyang Depression are calcites with lower hardness, which determine that the shale is brittle on the whole, but the degree of brittleness is relatively low and the shale shows the characteristics of "plastic". Scattered quartz debris, higher TOC content and younger diagenesis age play a negative role in formation fracturing. The stronger heterogeneity resulting from laminated structure is not conducive to form a complex fracture system during the fracturing process. In addition to the petrological characteristics, the shale fracturing effect is also affected by formation pressure, in situ stress and fracturing scheme, etc.
Hydrocarbon enrichment conditions and distribution in continental shale, West Liaohe Sag, Bohai Bay Basin
ShanYansheng, Zhang Jinchuan, Li Xiaoguang, Bi Caiqin, Tang Yue, Yuan Yuan
2016, 38(4): 496-501. doi: 10.11781/sysydz201604496
Abstract(1424) PDF-CN(1122)
Abstract:
We analyzed the hydrocarbon enrichment conditions in shale in the West Liaohe Sag of Bohai Bay Basin, and discussed the distribution features and pattern of shale oil and gas in continental rift basins, based on the tests of a large number of shale samples. The shale in the third and fourth members of Paleogene Shahejie Formation in the West Liaohe Sag has a large total thickness, wide distribution, good continuity, high TOC content (average 2.67%), and medium maturity (0.4%-1.5%). Organic matter is mainly sapropelic, and partially of humic type. The shale developed considerable pores, mostly intergranular and dissolution pores, and tectonic (with some interlayer) fractures. Favorable physical properties of reservoirs and high hydrocarbon content made the study area a good place for shale oil and gas enrichment. Controlled by sedimentary facies, organic matter type and thermal maturity, the West Liaohe Sag mainly yields shale oil, and regionally shale gas. From the bottom of the fourth member to the upper part of the third member of the Shehejie Formation, we found shale oil and gas, shale oil, and shale gas in turn. In the basin center, we mainly found shale oil, while on the slope we found interbedded shale oil and gas.
Micro-structure analysis of mudstones in the Middle Permian Zhesi Formation in Solun area, Inner Mongolia
Li Shizhen, Zhou Xingui, Wang Dandan, Zhang Jiaodong, Lin Yanhua, Zeng Qiunan, Zhang Wenhao
2016, 38(4): 502-508. doi: 10.11781/sysydz201604502
Abstract(926) PDF-CN(720)
Abstract:
The geochemical characteristics and micro-structure of dark mudstones from the Middle Permian Zhesi Formation in Solun area, Inner Mongolia were studied using field outcrops, samplings, and systematic analyses. Micro-pores (including interparticle, intraparticle and organic pores) and micro-fractures (including interlayer fractures in minerals, fractures between organic matter and minerals, and fractures in organic matter) developed in mudstones in the Zhesi Formation. Organic pores were not well developed in the Zhesi mudstones, mainly due to low TOC content and pore collapse under strong compaction effect. Micro-fractures were well developed thanks to high brittle mineral content. The characteristics of source rocks and reservoirs showed that mudstones in the Zhesi Formation have a good prospect for shale gas exploration. The areas with widespread mudstones rich in organic matter are targets for shale gas in the Upper Paleozoic in Northeast China.
Methane adsorption and sealing effects of shale: A case study of relict synclines in the southeastern Chongqing
Bao Yunjie, Deng Mo, Zhai Changbo, Liu Youxiang, Lü Junxiang, Yu Lingjie, Cao Taotao
2016, 38(4): 509-513. doi: 10.11781/sysydz201604509
Abstract(912) PDF-CN(734)
Abstract:
Universality and difference both exist in the methane adsorption of shale. This study concerns the influencing factors of shale gas occurrence, preservation and accumulation. The gas adsorption capacity of the Wufeng-Longmaxi shale in the relict synclinal district in the southeastern Chongqing was studied by means of isothermal adsorption, scanning electron microscopy, nitrogen adsorption and organic geochemical methods. The adsorption capacity of shale is controlled by some internal characteristics such as pore structure and organic matter features, and some external environment conditions such as temperature and pressure. The adsorption strength of shale under subsurface conditions can be predicted using a Langmuir model. The adsorption strength of Wufeng-Longmaxi shale from the relict synclinal district in the southeastern Chongqing has a critical depth at which adsorption strength reaches its peak value. Theore-tical analysis and experimental data of shale permeability determination under three axial stress concluded that the adsorption effect of shale resulted in the decrease of permeability which blocked the diffusion influences to shale gas flow, which was called as 'gas sealing effect'. The influences from this effect on gas preservation and enrichment boundary should be further studied.
Petrographic methods to distinguish organic matter type in shale
Zhao Jianhua, Jin Zhijun, Jin Zhenkui, Du Wei, Wen Xin, Geng Yikai
2016, 38(4): 514-520. doi: 10.11781/sysydz201604514
Abstract(1363) PDF-CN(1076)
Abstract:
Pores within organic matter are widely recognized as a significant component of pore systems in gas shale. These pores form not only in kerogen, but also in solid bitumen, with different morphology and development degree. The source of organic matter can be divided into depositional and migrated organic matter. Depositional organic matter is deposited in direct contact with detrital mineral grains and comprises depositional kerogen and its alteration products. Migrated organic matter occurs in mineral pores initiatially as bitumen or oil that filled the cement-lined pores and cement would separate bitumen or oil from mineral grains and may evolve into solid bitumen and pyrobitumen during maturation. Authigenic quartz has a dual role in influencing shale porosity. On one hand, it reduces shale porosity by filling pore space,while on the other hand,it supports pore preservation by inhibiting shale compaction and preserving pore space for migrated organic matter. There are pores both in depositional organic matter and migrated organic matter. Migrated organic matter is present in three-dimensional connected mineral pores, which produces a pore network with higher reservoir quality than a pore network associated with only depositional organic matter. Migrated organic matter decreases from bottom to top in the Wufeng-Longamxi formations, the connected pore network decreases accordingly, and reservoir quality becomes poorer.
Lowest limit for the gas-bearing capacity of reservoirs in the eastern Sulige gas field, Ordos Basin
Chen Zhanjun, Ren Zhanli, Wang Shuhui, Liu Ping, Xue Fen, Deng Yaren, Qi Kai, Cao Zhanpeng
2016, 38(4): 521-527. doi: 10.11781/sysydz201604521
Abstract(1183) PDF-CN(740)
Abstract:
According to the definition and characteristics of the lowest limit for reservoir gas-bearing capacity, we carried out statistical and accumulation mechanism studies in the eastern Sulige gas field in the Ordos Basin. The two methods reached a similar conclusion. The lowest limits for the porosity and permeability of the eighth member of Shihezi Formation (He8) are 2.223% and 0.005 7×10-3 μm2, respectively. The lowest limits for the porosity and permeability of the first member of Shanxi Formation (Shan1) are 1.605% and 0.004 4×10-3 μm2, respectively, which are both higher than those of He8. The lowest limit for reservoir gas-bearing capacity is negatively related to charging force. We collected samples from the reservoirs with physical properties close to the lowest limit, and tested their gas saturation. The gas saturation of the reservoirs with physical properties close to the lowest limit is extremely low, and obviously increases in reservoirs with better physical properties. Theoretical analyses are consistent with coring results.
Compaction factors of tight reservoirs in the seventh member of Yanchang Formation in the central Ordos Basin during the Late Triassic
Shi Baohong, Huang Jing, Chen Liu, Yang Fan, Lü Jianwen
2016, 38(4): 528-535. doi: 10.11781/sysydz201604528
Abstract(964) PDF-CN(918)
Abstract:
The Chang7 reservoir (the seventh member of Yanchang Formation) in the Ordos Basin, with an average porosity of 9% and permeability of 0.1× 10-3 μm2, is a tight reservoir. Reservoirs are mainly sandy debris flows and turbidite sandstones in a semi-deep and deep lacustrine gravity flow environment, featured by fine granularity, high filler content, complicated pore and throat shape, enriched secondary dissolved feldspar pores, and poor primary intergranular porosity. The influencing factors for reservoir physical properties were analyzed according to micro test data such as cast thin section, X-ray diffraction, fluid inclusion and electron probe microscopy. Sedimentation, diagenesis and hydrocarbon charging are the three major factors affecting reservoir physical properties. The sedimentary characteristics of semi-deep and deep lacustrine sandstones were key factors that caused intense compaction and cementation in reservoirs. As a result, sandstone porosity may decrease by 22%. On the other hand, feldspars were dissolved by organic acid liquids produced by the reaction of hydrocarbon emplacement, which in turn improved physical property. Alkaline reservoir fluid after hydrocarbon charging was beneficial to the cementation of ferrous calcites, which was critical to reservoir tightening.
Movable oil and its controlling factors in tight sandstones: A Case study of the Triassic Chang7 reservoir, Yanchang Formation, Ordos Basin
Cui Jingwei, Zhu Rukai, Li Shixiang, Yang Zhi, Zhang Zhongyi
2016, 38(4): 536-542. doi: 10.11781/sysydz201604536
Abstract(1138) PDF-CN(720)
Abstract:
Tight oil in place in China has been estimated over 10 billion tons, but it is difficult to define [JP]the availably producible reserves. Several efficient ways, including perfecting Quartz Crystal Microbalance with Dissipation (QCM-D) to evaluate adsorption ratio per unit in subsurface cores, applying mercury injection capillary pressure(MICP) and nitrogen adsorption to define the lower oily limit and the effective specific surface area, and combining oil testing results in confined cores, were utilized to evaluate the movable oil in the Triassic Chang7 reservoir, Yanchang Formation, Ordos Basin. The results indicated that the thickness of oil adsorbed on tight sandstone surfaces was 15.6 nm with an intensity around 13 mg/m2, the lowest oily limit was around 18 nm, the effective specific surface area was around 1m2/g, the porosity was around 6%-10%, and the ratio of free oil was around 14.3%-48.6%. All these results were comparable with the NMR experiments. Several factors controlled the movable oil amounts in tight sandstones, including crude oil density and viscosity, effective specific surface area, effective porosity volume and mineral constituents. For specific region or layer, the amounts of movable oil is parametrically controlled by pore surface area/effective porosity volume.
Diagenesis and controlling factors of tight sandstone reservoirs: A case study of the lower member of Silurian Kepingtage Formation in Shuntuoguole area, Tarim Basin
Zhang Hanbing, Peng Jun, Yang Suju, Lu Ming, Xia Qingsong, Li Bin
2016, 38(4): 543-550. doi: 10.11781/sysydz201604543
Abstract(1204) PDF-CN(682)
Abstract:
Tight sandstone reservoirs in the lower member of Silurian Kepingtage Formation in Shuntuoguole area of the Tarim Basin were studied through core observation, thin section identification, scanning electron microscopy, X-ray diffraction and fluid inclusion homogenization temperatures. They mainly consist of fine-grained debris sandstones with poor physical properties. Five types of diagenetic effects occurred, including compaction, cementation, erosion, metasomatism, and tectonic fracturing. Compaction made the reservoir physical properties become poorer, while erosion improved them. They are mainly within the middle diagenesis stage A, and locally in the middle diagenesis stage B. Diagenetic effects were dominated by many factors. Sedimentary environment and debris predominated the degree of compaction and erosion, burial history and temperature macroscopically controlled diagenesis development, while hydrocarbon charging microscopically reduced the cementation rate and enhanced the erosion of soluble components.
Petrophysical property limits of effective tight oil reservoirs in the lower part of the first member of Cretaceous Tengger Formation, A'nan Sag, Erlian Basin, North China
Zhang Yiming, Fu Xiaodong, Guo Yongjun, Shou Jianfeng, Zhou Jingao, Li Bin, Zhang Tianfu, Lan Baofeng
2016, 38(4): 551-558. doi: 10.11781/sysydz201604551
Abstract(1397) PDF-CN(736)
Abstract:
The lower part of the first member of Cretaceous Tengger Formation (K1t1x) is a main target for tight oil exploration in the A'nan Sag. Two favorable tight reservoir types including tuffites and sandstones have been found. The porosity and permeability of tight reservoirs change greatly. The heterogeneity of oil-bearing strata is strong, which is controlled obviously by porosity and permeability. Based on physical property measurements, well testing, mercury injection data and so on, we determined the petrophysical property cutoffs of effective tight oil re-servoirs in K1t1x using an oil-bearing occurrence method, experimental statistics, distribution function, well testing and minimum effective pore throat. The cutoff of effective reservoir porosity of tuffites is 4.0%, and that of permeability is 0.008×10-3 μm2. The cutoff of effective reservoir porosity of sandstones is 5.0%, and that of permeability is 0.05×10-3 μm2. The determination of cutoffs of an effective reservoir provides a scientific basis for "sweet spot" reservoir prediction, resource potential evaluation and exploration target selection of tight oil.
Gao Junyang
2016, 38(4): 559-559.
Abstract(662) PDF-CN(733)
Abstract:

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