石油实验地质

2016, 38(3): .

Abstract(662) PDF-CN(1610)

Abstract:

Salt tectonics and its relationship to hydrocarbon accumulation in salt basins with a lower rifted section and an upper continental marginal section: A case study of the Lower Congo-Congo Fan basins and the Kwanza Basin in West Africa

Sun Ziming, He Zhiliang

2016, 38(3): 287-292. doi: 10.11781/sysydz201603287

Abstract(1245) PDF-CN(1495)

Abstract:
The West African coastal basins, such as the Gabon Coastal Basin, Lower Congo Basin and Kwanza Basin, are typical oil-bearing salt basins with a lower rifted section and an upper continental marginal section. Three evolution stages can be identified in those basins, including a rifting period (the Early Cretaceous Valanginian to Barremian), a transitional period (Aptian to the early Albian) and a passive continental margin period (the early Cretaceous Albian to present), thus developing three tectono-sedimentary sequences from base to top: pre-salt, evaporites, and post-salt. On one hand, under the influence of the uplifting African craton and the continuing subsidence of the Atlantic passive margin from Paleogene to present, and taking the evaporite layer as a detachment, a gravity gliding tectonic deformation layer was formed in the post-salt sequence. This layer represents a cover-detached structure with complex deformation, various salt structural styles, and obvious tectonic zonation from east to west. On the other hand, tectonic deformation in the pre-salt tectono-sedimentary sequence was very weak, therefore, basement-related geological structures generally remained unchanged since South America and Africa separated some 165 million years ago. Salt tectonics controlled the formation and distribution of post-salt reservoirs and traps. At the same time, the salt layer works as a good regional seal for the subsalt sequence that can be interpreted as a boundary between post-salt and pre-salt petroleum systems. Therefore, in general terms, oil and gas generated in the subsalt petroleum system can only migrate and accumulate locally, particularly in deep to ultra-deep water areas where the salt strata have been thickened. However, in shallower water areas, where salt thickness was dramatically thinned or missing, subsalt oil and gas may migrate into the post-salt sequence through salt windows and/or connecting faults. Existing near-shore post-salt fields in West Africa provide support for this migration and accumulation process.

Sedimentation mechanism and petroleum significance of calcareous cements in continental clastic rocks: Comparison between the Kongdian Formation in the Jiyang Depression and the Xujiahe Formation in the western Sichuan Basin

Tan Xianfeng, Jiang Wei, Wu Kangjun, Wang Hao, Xu Tiankun, Chen Sujun, Ran Tian

2016, 38(3): 293-302. doi: 10.11781/sysydz201603293

Abstract(1386) PDF-CN(1568)

Abstract:
The mechanism of calcareous cementation in clastic rocks in the Kongdian Formation in the Jiyang Depression and the Xujiahe Formation in the western Sichuan Basin were studied by means of cathode luminescence, scanning electron microscopy, inclusion homogenization temperature measurement, isotope content of carbon and oxygen, and chemical ion. The calcareous cements mainly consist of carbonates, hard gypsum and fluorite. Their microscopic characteristics are influenced by cementation time and environment. Calcium sources and precipitation controlling factors affect the mechanism of calcareous cementation. The calcium sources for calcareous cements mainly include meteoric water eluviation, feldspar dissolution, compaction and dissolution, thermochemical action of organic salt rocks, and clay mineral transformation. The precipitation mechanism of calcareous cements is not influenced by a single factor, but by many factors such as temperature and pressure, pH value and the concentration of chemical ions. The time of calcareous cementation is divided into early, middle and late. The physical properties of reservoirs are influenced by the time of calcareous cementation. Calcareous cements during the early diagenetic stage are constructive to the reservoir, while those during the late diagenetic stage are destructive.

LST and T-HST featured by impulse in continental sequences in the Western Sichuan Depression

Zhang Zhuang, Ye Sujuan, Yang Keming, Zhu Hongquan, Yang Yingtao, Li Min, Zhang Shihua

2016, 38(3): 303-310. doi: 10.11781/sysydz201603303

Abstract(1142) PDF-CN(1491)

Abstract:
According to the basic concepts of sequence stratigraphy and the controlling factors of compressional basins, the continental sequences in the Western Sichuan Depression were studied, based on field outcrops, well cores and logging and seismic data. The episodic compressions of surrounding mountains controlled the sequence stratigraphy and sedimentary infill pattern in the western Sichuan foreland basins. Stress accumulated slowly for a long time, and released instantly. Lake-level (basal level) and accommodation space changed in response to periodic compression and relaxation, resulting in LST (Lowstand System Tract) and T-HST (Transgressive-Highstand System Tract). Coarse-grained sedimentary bodies such as braided river and delta are dominant in LST, while T-HST in the upper part of the sequence is composed of fine-grained semi-deep lacustrine sediments. Vertically, delta facies sand bodies are interbedded with lacustrine mudstones, favorable for hydrocarbon generation, accumulation, preservation and trap formation. Lithologic reservoirs and lithologic-tectonic reservoirs formed by coarse grains at the bottom of the sequence are important exploration targets. Meanwhile, lithologic reservoirs in the upper part of the sequence on the basin margin provide additional opportunities.

Diagenetic characteristics of dolomites in the Cambrian Loushanguan Group in southeastern Sichuan Basin

Jiang Wenjian, Hou Mingcai, Xing Fengcun, Xu Shenglin, Ling Liangbiao

2016, 38(3): 311-319. doi: 10.11781/sysydz201603311

Abstract(1341) PDF-CN(1054)

Abstract:
Based on the comprehensive studies of petrology, carbon and oxygen isotopes, and cathodoluminescence characteristics, it has been shown that dolomites from the Jingzhu and Zhongba outcrop sections of the Cambrian Loushanguan Group have experienced multiple diagenetic effects such as dolomitization, dissolution, cementation and silicification. There are four types of dolomite: penecontemporaneous, seepage refluxing, buried, and hydrothermal. Four diagenetic stages were divided into penecontemporaneous, early, late and epidiagenetic. The influencing factors of diagenetic evolution and pore development were analyzed. Diagenetic evolution was mainly affected by the sedimentary environment, the original structure of sediments and sedimentary cycles. Micrite dolomites formed in tidal flat and lagoon environments have a poor original porosity, and the late diagenetic fluid alteration was weak. Grain dolomites and crystalline dolomites formed in a beach environment have lots of primary pores, and their porosity was further improved by late diagenetic fluid alteration. As a result, they are more favorable reservoirs for oil and gas.

Six characteristics and main controlling factors of shale reservoirs in the Wufeng-Longmaxi formations, southeastern Sichuan Basin

Zhang Hanrong, Wang Qiang, Ni Kai, Li Chunyan

2016, 38(3): 320-325. doi: 10.11781/sysydz201603320

Abstract(1500) PDF-CN(1428)

Abstract:
Shale gas exploration in the Wufeng-Longmaxi formations in the southeastern Sichuan Basin showed different results. Some wells were high yielding, some were low yielding, and some were dry. Well core description, geochemical analysis, SEM, X-ray diffraction, field gas content tests, and well logging analysis were applied to compare samples from over 10 shale gas wells. Six properties were studied, including lithology, geochemical features, brittleness, physical properties, gas-bearing capacity, and electrical resistivity. Lithology, geochemical features, and brittleness show good correlation. For example, radiolarian carbonaceous graptolite shale has high TOC content and brittleness index. These three properties were controlled by sedimentary environment and facies, and can be compared among wells in the study area. Physical properties are positively correlated with gas-bearing capacity. They were affected by tectonic deformations, and vary obviously among wells. Physical properties are positively correlated with TOC content. Shale attitude and fault development are the main factors which affect gas content because the horizontal permeability of shale is several times larger than vertical permeability. Gas content also affected shale porosity and permeability. Radiolarian carbonaceous graptolite shales with few faults are favorable for the preservation of pressure and pores, and can form industrial reservoirs featured by high GR, high resistivity, relatively high AC, high U content, low KTH, low NGR, and low density.

Characteristics of fault structure and its control on hydrocarbon accumulation in the eastern part of southwestern Tarim Basin

He Juan, Wang Yi, Liu Shilin, He Dengfa

2016, 38(3): 326-332. doi: 10.11781/sysydz201603326

Abstract(1173) PDF-CN(965)

Abstract:
High resolution interpretations of seismic profiles in the eastern part of southwestern Tarim Basin have been accomplished with the application of fault-related folding geometry principles. The Mazhatage fault zone developed both shallow and deep fault systems, and formed fault propagation folds in the deep fault system and thrust structures in the shallow fault system. The Yubei1 tectonic zone was deformed in the Paleozoic strata, and developed mixed fault propagation folds. The Southern Hetian thrust and nappe fault zone is located in front of the western Kunlun orogeny, and developed structural wedges. The Late Caledonian-Early Hercynian, Late Hercynian and Himalayan periods are important for structural formation and evolution in this area. Faults controlled hydrocarbon accumulation in the study area. A large-scale tilting movement took place in the study area during the Himalayan period. Therefore, the pivot part of Maigaiti slope and the southern margin of Bachu uplift are hydrocarbon enrichment zones.

Structural pattern of the Maigaiti Slope in the Tarim Basin

Shi Zheng, Xun Zhengyao

2016, 38(3): 333-339. doi: 10.11781/sysydz201603333

Abstract(1215) PDF-CN(1100)

Abstract:
The Maigaiti Slope is a secondary structural unit in the Tarim Basin, which underwent multiple tectonic movements. The stacking of structural deformation was controlled by basement structures or faults, multiple tectonic movements, stress field transition and regional detachment levels. According to the structural origin, the structural pattern in the study area can be divided into compressional, strike-slip, salt-related and magmatic structure, and each of them can be subdivided into several subtypes. The multiple tectonic movements led to the transformation of pre-existing structures and the formation of new structures. Various tectonic patterns were observed, including basement faults-increasing gypsum salt bed-back thrust, pre-existing uplift-draping anticline, pop-up block hill-draping anticline, magma diapir-draping anticline, basement-involved fault-synthetic/antithetic cap rock detachment, strike-slip fault-shallow detachment, and imbricate structure.

Attributes of sweet spots in the Devonian Woodford shales in Oklahoma, USA

Gao Zhanjing, Zheng Herong, Huang tao

2016, 38(3): 340-345. doi: 10.11781/sysydz201603340

Abstract(1824) PDF-CN(1639)

Abstract:
The Devonian Woodford shale play in Oklahoma is one of the big unconventional shale oil and gas production fields in USA, which covers the Anadarko, Ardmore and Arkoma basins and Cherokee Platform. The shales are rich in organic matter, with the maximum content of 14%. They have entered condensate gas or mature oil windows. The vitrinite reflectance (R_o) values range from 0.6% to 1.4%. Shale thickness exceeds 20 m. The water isolating layer beneath the shale formation should be at least 15 meters thick to avoid fractures made by hydraulic fracturing reaching the water bearing layer. Shale formations with a TOC content of 7% with chert layers with well developed fractures are the most promising. Well locations should be far away from major faults. Based on the attributes of sweet spots, we should design a specific drilling program to reduce drilling risk and cost and achieve high profit.

Adsorption characteristics of shale reservoirs in the Jingmen area and application of adsorption potential theory

Yue Changtao, Li Shuyuan, Li Linyue, Wen Hailong

2016, 38(3): 346-353. doi: 10.11781/sysydz201603346

Abstract(886) PDF-CN(1465)

Abstract:
Organic carbon content, carbon isotope analysis of kerogen, X-ray diffraction and low-temperature CO₂+N₂ adsorption tests were usedto investigate the conventional geological properties and pore characteristics of shale samples from the Jingmen area. The results show that the shale samples have high organic carbon content, high maturity, and well developed pore structure. A gravimetric method was used to make isothermal adsorption experiments, and an isothermal adsorption model was established to measure the effect of moisture and temperatureon adsorption. Results show that the shale samples have good adsorption properties with an average adsorption volume of 2.52 mL/g. A Langmuir model fits well with the adsorption curves. The adsorption capacity of shale samples decreases as moisture content and temperature increase. Adsorption potential theory was used to explain the controlling factors, and the results showed that it is more useful when adsorption potential is high.

Characteristics of carbonate reservoirs in the Timan-Pechora Basin in Russia: The Trebs and Titov oil fields as examples

Yang Shiwei, Shi Danni

2016, 38(3): 354-359. doi: 10.11781/sysydz201603354

Abstract(1270) PDF-CN(1117)

Abstract:
The Timan-Pechora Basin is a petroliferous basin in Russia. It is a composite basin of rift, passive margin, and foreland. From the Early Riphing to Early Carboniferous, a rift, passive margin, and shallow continental shelf developed in the basin. From the Late Carboniferous to Quaternary, the Ural orogeny and post-orogeny foreland developed. Three sets of carbonate reservoirs were formed in the basin, including the Lower Paleozoic, Lower-Upper Devonian (Frasnian-Famennian), and Carboniferous-Lower Permian. They were controlled by both sedimentary and diagenetic effects. Favorable sedimentary facies and unconformities controlled the distribution of effective reservoirs. Reservoir porosity includes primary pores and dissolution vugs formed by karst. Reservoir physical properties vary both horizontally and vertically. Generally, the formation 30-40 m below an unconformity is the most favorable reservoir position. The reservoirs have a strong heterogeneity, and are featured by low porosity and low permeability, which restricts hydrocarbon exploitation. Data from 12 carbonate reservoirs with a long development history in the study area were analyzed, confirming low recovery rates and low recovery levels.

Characteristics and genesis of carbonate reservoirs in the Mishrif MB₂¹ member in the Missan oil fields, Iraq

Zhang Yikai, Kang An, Min Xiaogang, Li Zhiming, Li Weichao, Gao Huijun

2016, 38(3): 360-365. doi: 10.11781/sysydz201603360

Abstract(1628) PDF-CN(1793)

Abstract:
The characteristics and genesis of carbonate reservoirs in the Mishrif MB₂¹ member in the Missan oil fields were studied based on core, well logging, seismic and production data. The reservoirs were mainly deposited in a carbonate open platform sedimentary environment, and developed several subfacies such as bioclastic shoals, bioherms and open subtidal deposits. Rudist grainstones, skeletal grainstones, skeletal peloidal grainstones and skeletal peloidal packstones were found. Primary intergranular pores, secondary dissolution pores, mouldic pores, micro-pores associated with matrix, a small quantity of micro-vuggy and micro-fractures provided space for hydrocarbon accumulation. Controlled by deposition and diagenesis, reservoir distribution was similar laterally, but varied obviously vertically and showed a strong heterogeneity, which restricted oil development.

Hydrocarbon potential of source rocks in the Middle Triassic Leikoupo Formation in the Western Sichuan Depression

Yang Keming

2016, 38(3): 366-374. doi: 10.11781/sysydz201603366

Abstract(1145) PDF-CN(998)

Abstract:
The Middle Triassic Leikoupo Formation in the Western Sichuan Depression is an important marine target for natural gas exploration in the Sichuan Basin in recent years. Geochemical analyses were made with rock samples from the Leikoupo Formation. Seismic interpretation and sedimentary data were studied. Source rocks in the Leikoupo Formation mainly distribute in Dayi, Wenjiang, Pengzhou, Guanghan and Xiaoquan. They are about 250-350 m thick, and have a TOC content of 0.4%-0.6%. The source rocks were deposited in a sedimentary environment with high biological productivity, quiescent depositional setting, restricted seawater circulation, high salinity, anoxic bottom water and low deposition rate, all favorable for the preservation of organic matter. The comprehensive analyses of organic geochemistry, inorganic geochemistry and organic petrology indicated that, the source rocks in the Leikoupo Formation displayed a low abundance of organic matter with good organic type. Solid bitumen and ultramicro macerals were observed on photomicrographs. Organic type index (TI) ranges from 12.5%-98.03%, indicating Type Ⅱ₁-Ⅱ₂ source rocks. Organic matter was mainly derived from hydroplankton, showing a good hydrocarbon potential.

Weathering effects on high-maturity organic matter in a black rock series: A case study of the Yuertusi Formation in Kalpin area, Tarim Basin

Tao Guoliang, Shen Baojian, Tenger Boltsjin, Yang Yunfeng, Xu Ershe, Pan Anyang

2016, 38(3): 375-381. doi: 10.11781/sysydz201603375

Abstract(1246) PDF-CN(1113)

Abstract:
The effects of weathering on organic matter of black shales has been studied using organic geochemistry, scanning electron microscopy and X-ray fluorescence energy spectrum. The black shales were collected from the Lower Cambrian Yuertusi Formation along Dong'ergou section in Kalpin area, Tarim Basin. As weathering increased, organic abundance became much smaller, and hydrocarbon generation potential became poorer. The maximum weathering losses of organic matter and chloroform bitumen "A" were more than 95% in black shales and less than 50% in siliceous rocks, indicating that siliceous rocks were more resistant to weathering. Climate and surface exposure time were the main causes for rock weathering. Mineral composition and organic matter occurrence determined weathering degree. Free organic matter occurring in over-mature shales was easily lost through weathering. In petroleum evaluation, it is important to not only study the present geochemical features of source rocks, but also to considerweathering effects.

Maturity history of source rocks in the Eocene Niubao Formation, Lunpola Basin

Pan Lei, Cao Qiang, Liu Yiming, Li Yiteng, Wang Yan, Li Zhiquan

2016, 38(3): 382-388. doi: 10.11781/sysydz201603382

Abstract(1476) PDF-CN(891)

Abstract:
Three sets of source rocks developed upwards in the Eocene Niubao Formation in the Lunpola Basin, i.e., the middle part of the second member of Niubao Formation (E₂n₂²), the upper part of the second member of Niubao Formation (E₂n₂³), and the lower part of the third member of Niubao Formation (E₂n₃¹). Based on drilling, seismic and hydrocarbon fluid inclusion analyses, the thermal evolution history of the basin and the maturity history of source rocks in the Niubao Formation were systematically analyzed with basin simulation technology. From the E₂n₃ to the third member of the Oligocene Dingqinghu Formation, the paleogeothermal gradient in the Lunpola Basin consistently decreases from 66.7 to 40℃/km, showing the characteristics of a typical heating basin. The growth of paleogeothermal gradient is clearly related to regional tectonic uplifting. The source rocks in the E₂n₂² and E₂n₂³ became mature early and have a higher maturity. They entered oil generation thresholds during the middle-late Eocene (46.4-37.5 Ma) and early Oligocene (36.6-33.5 Ma), respectively. At present, they are mature and generating oil (R_o=0.7%-1.3%), and serve as the main source rock in the study area. At present, the thermal evolution extent of E₂n₂² and E₂n₂³ hydrocarbon source rocks in the Jiangriacuo Sag in the west is the highest, and its hydrocarbon forming and supplying ability is superior to the Jiangjiangcuo and Pacuo sags in the center and east.

Characterization of micro pore throat radius distribution in tight oil reservoirs by NMR and high pressure mercury injection

Gong Yanjie, Liu Shaobo, Zhao Mengjun, Xie Hongbing, Liu Keyu

2016, 38(3): 389-394. doi: 10.11781/sysydz201603389

Abstract(1512) PDF-CN(1136)

Abstract:
Through the design of an algorithm, the conversion coefficient of NMR T₂ relaxation time and pore throat radius was optimized by using the pore throat distribution data in tight oil reservoirs obtained from mercury injection experiments. The precision of the NMR characterization of pore distribution was improved. Methods were used in the characterization of Cretaceous tight oil pore radius distribution in the southern Songliao Basin. Pore radius of samples with oil saturation less than 10% were concentrated in the 10-300 nm range, while those with oil saturation between 10% and 40% were mainly 20-1 000 nm. Unlike these samples, the pore radius of samples with oil saturation greater than 40% were concentrated in the 20-3 000 nm range.Experimental results showed that the development of different levels of microporosity in tight oil reservoirs controlled the oiliness properties.

A new method for the calculation of secondary porosity originating from the dissolution of feldspars in deeply buried formations and its application: A case study of the Chang 8₁ Formation in Longdong area, Ordos Basin

Yang Youyun, Liu Xiqiang, Sun Rui

2016, 38(3): 395-401. doi: 10.11781/sysydz201603395

Abstract(1289) PDF-CN(1091)

Abstract:
Secondary porosity is an important accumulation space in clastic reservoirs. Among secondary pores, those pores originating from the dissolution of feldspars are dominant. A new method to calculate the volumes of secondary porosity from the dissolution of feldspars in deeply buried formations based on thermodynamic principle is proposed. The calculation method is as follows. The volume of secondary porosity originating from the dissolution of potassium feldspars=0.28×kaolinite content or 0.36×illite content. The volume of secondary porosity originating from the dissolution of albite feldspars=0.10×kaolinite content or 0.17×illite content. The volume of secondary porosity originating from the dissolution of anorthite feldspars=0.014×kaolinite content or 0.08×illite content. After a thorough investigation of petrologic characteristics, the new calculation method was applied to the Chang 8₁ Formation in Longdong area, Ordos Basin. The volumes of secondary porosity originating from the dissolution of feldspars in deeply buried formations in the Chang 8₁ Formation in the study area were calculated with the new method, and were compared with measured and simulated porosities. The average value of calculated secondary porosity from the dissolution of feldspars of 51 core samples from the Chang 8₁ Formation is 1.32%, which is close to the average measured value (1.44%) for those samples. The comparison between calculated and simulated results also confirms the reliability of this new method.

NMR analysis of the physical change of oil shales during in situ pyrolysis at different temperatures

Li Guangyou, Ma Zhongliang, Zheng Jiaxi, Bao Fang, Zheng Lunju

2016, 38(3): 402-406. doi: 10.11781/sysydz201603402

Abstract(1550) PDF-CN(1171)

Abstract:
The connectivity between pores and fissures during in situ oil shale pyrolysis is an important element which controls shale oil and gas recoverable amount. However, conventional petrophysical testing methods can not cover all levels of pores and fissures in oil shales. Nuclear magnetic resonance (NMR) can show fluids in core pores and fissures, hence can be used to identify different levels of pores and fissures. We carried out NMR tests with oil shale samples by simulating the same conditions as 500 m underground and heating the samples to different temperatures. Results showed that the porosity of oil shales change according to temperature during in situ exploitation. Porosity increases from 250 to 350℃, decreases slightly from 350 to 400℃, and then increases again after 400℃. Permeability remains stable when temperature is lower than 400℃, increases by 10² times from 400 to 450℃, and increases by 10⁴ times at 500℃. The in situ retorting of oil shales should be made at a temperature higher than 400℃; however, oil shales underground might not reach 400℃ in many areas. In this case, we should explore at a higher temperature and heat for longer time, or fracture oil shales before heating.

Characterization of the physical properties of coal reservoirs in the western Guizhou and eastern Yunnan by X-ray computed tomography

Xiong Bo, Liu Kun, Guo Kai, Zhao Guangmin

2016, 38(3): 407-412. doi: 10.11781/sysydz201603407

Abstract(916) PDF-CN(849)

Abstract:
The western Guizhou and eastern Yunnan are potential exploration areas for coal bed methane (CBM) in South China, and their favorable CBM potential has been demonstrated by CBM exploration and pilot tests. In this paper, the physical properties of coal reservoirs in the study area were systematically studied by means of X-ray computed tomography (X-CT). The research showed that X-CT could identify 4 kinds of media: mineral, durain, vitrain and pore. The CT number of mineral, durain, vitrain and pore were approximately >1 800, 1 500-1 800, 1 000-1 500 and <1 000 Hounsfield unit (HU), respectively. Their specific CT number varied from sample to sample. The estimated porosity values of coals ranged from 3.33% to 7.14%, and mineral contents ranged from 0.11% to 89.03% by means of X-CT, which correlated well with the porosities determined using the helium gas method and proximate analysis. X-CT scans showed that under the influence of stress, undeformed coal has the highest homogeneity, mylonitic coal has the highest heterogeneity, and proto-cataclastic and cataclastic coals were between them. If coals were not affected by stress, their composition heterogeneity in the axial direction was relatively good. The later stress action caused the uneven distribution of coal components, pores, fractures and minerals, which enhanced the heterogeneity of coals. A three-dimensional model of coals was built to show the quantification and 3D visualization of the spatial disposition of minerals, pores and fractures of coals in these areas.

Quantitative analysis of pore genetic types in the Silurian clastic rocks in the Tarim Basin: A case study of the Kepingtage Formation in well Shun9

Zhang Yongdong, Wang Shuyi

2016, 38(3): 413-417. doi: 10.11781/sysydz201603413

Abstract(1015) PDF-CN(1148)

Abstract:
The identification of pore genetic types in clastic reservoirs affects reservoir prediction. The Silurian reservoirs in the Tarim Basin mainly include primary-secondary composite pores and micro-pores. It is difficult to identify their genetic types by conventional cast thin section observation. A case study was made in the Silurian reservoirs in well Shun9 based on cast thin section observations. Primary pores decrease to a similar extent under compression in formations of similar lithologies buried to similar conditions, resulting in similar residual primary pore contents. We studied the lithologic features and measured porosity of formations with similar burial depths, and quantitatively determined the contents of pores of different genetic types. Primary residual intergranular pores account for less than 4.6% (measured porosity 3.2%-14.6%) in the Silurian reservoirs in well Shun9. Present reservoirs with medium and low porosities were formed due to secondary dissolution, and the reservoirs with high porosities were mainly composed of secondary pores. The quantitative analysis is helpful for the identification of pore genetic types.

Application of micron CT in the characterization of microstructure in source rocks

Huang Zhenkai, Chen Jianping, Wang Yijun, Wang Huajian, Deng Chunping

2016, 38(3): 418-422. doi: 10.11781/sysydz201603418

Abstract(1764) PDF-CN(1516)

Abstract:
Three dimensional imaging micron CT was used to observe microstructure character of hydrocarbon source rocks in the first member of Cretaceous Qingshankou Formation of the Songliao Basin. The pore diameter is in the range of 0.7-25 μm, and the pore types are mainly intergranular and intragranular. Pore channels are formed with connected pore throats. The sizes of biological detritus (or organic matter) are micrometers to a hundred micrometers, mainly distributed in medium-density mineral matrix, and the biological types are mainly plankton and shellfish organisms. As a new tool and research method, the micron CT 3D reconstruction technology can be applied for the description of microstructure character in rocks. However, there are still some problems such as image resolution, image processing of 2D scans and the geological representativeness of the experimental results. In this paper, reasons for these problems have been discussed and subsequently preliminary solutions have been put forward.

Yang Fan

2016, 38(3): 423-423.

Abstract(619) PDF-CN(948)

Abstract:

2016 Vol. 38, No. 3

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