[Purpose/Significance] Aiming at the current situation that university libraries have entered a critical period of modernization and connotation development, this paper discusses how to construct a knowledge service system to adapt to the development trend of the new era and achieve the connotation transformation and development of university library undertakings. [Method/Process] Taking the practice and innovative exploration of the Library of Beijing University of Technology for more than 40 years as an example, this paper proposes a systematic knowledge service system from the aspects of construction objectives and positioning, main service segments, and management and operation mechanisms. In addition, it is also advocated that university libraries actively participate in the metacosmic revolution, break the constraints of time and space, and build a metacosmic knowledge service that integrates virtual and real knowledge. [Results/Conclusion] First-rate university libraries need to seize the development opportunities of the new era, boldly become the vanguard of transformation and development, innovate systems and mechanisms, deeply carry out knowledge services, and create a knowledge innovation and development platform that can release digital productivity by building a knowledge service system, making contributions to promoting the digital construction of higher education.

To reveal the effects of lacustrine hydrothermal activities on the organic matter input of source rocks and the formation of excellent source rocks in the Ordos Basin during the Middle and Late Triassic Yanchang period, samples of the Yanchang Formation in the YK1 well in the southern Ordos Basin were selected; source rock evaluations, element geochemical analysis, and palynofacies studies were systematically conducted. The results show that excellent source rocks are developed in the Chang 7-3 interval. The intensity indicators of hydrothermal activity (IIHAs), namely Al/(Al + Fe + Mn) (IIHA1) and (Fe + Mn)/Ti (IIHA2) show that the lake underwent three episodes of obvious thermal fluid activity during the depositional period of the Chang 7-Chang 6 members of which the Chang 7-3 period was the peak of hydrothermal activity. The main hydrocarbon-generating components in the source rocks of the Yanchang Formation were granular amorphous organic matter (AOM) and algae and gelified particles were the secondary hydrocarbon-generating components. Three palynofacies assemblages have been identified in the source rocks. Assemblage A is distributed in the Chang 8-Chang 9 members and Chang 6-2 + 3 interval. The organic matter present in this assemblage mainly consists of type III and translucent lignocellulosic fragments and gelified particles comprise the dominant organic debris. Assemblage B is distributed in the Chang 7-3 interval which consists mainly of Type I and Type II organic matter and is characterized by high abundances of algae and AOM. Assemblage C is distributed in the Chang 7-1 + 2 interval and consists mainly of Type II organic matter which is characterized by the simultaneous development of AOM and phytoclasts. The correlations between the contents of AOM and algae in the source rocks and the IIHAs indicate that hydrothermal activity may have led to the development of algae and source rock formation. The distribution of AOM and algae show consistently high contents over the entire Chang 7-3 interval which are not only coupled with the peak of total organic carbon content, liquid hydrocarbon potential, hydrogen index, and peak of hydrothermal activity but also shows different degrees of correlation with the IIHAs. Their relationships indicate that the peak of the lake's hydrothermal activity may have induced algae and plankton blooms, which may have been one of the important controlling factors for the formation of excellent source rocks. The close relationship between the IIHA and sulfur content indicates that hydrothermal fluids may have further deprived the oxygen of lake bottom and formed a reducing environment which was helpful for the preservation of organic matter and deposition of excellent source rocks.

A recent drilling operation in the Triassic Yanchang Formation (Tongchuan District of the Ordos Basin, north-central China) reached a black shale bed with an average in-situ gas content of 1.11 g/ml. Subsequent total organic carbon (TOC) content measurements and rock-eval analysis showed that the black shale section was generally classified as excellent source rock, with TOC contents commonly over 12% and an average genetic potential reaching 90 mg HC/g rock. The black shale samples of the Yanchang Formation contain kerogen of types I and II1, indicating the presence of oil source rocks, and the T-max values range from 438 to 442 degrees C, which indicate a maturity stage in the early oil window. To reconstruct the depositional environment of the black shales with high TOC contents, various geochemical elements and their ratios were analyzed, yielding a number of interesting results: (i) the paleoclimate indexes CIA, CIW and C-values range from 50 to 72 (mean 65), 56 to 85 (mean 75), and 0.8 to 2.6 (mean 1.5), respectively, indicating humid conditions during the sedimentation period of the black shales; (ii) the redox conditions during the sedimentation of the black shales were dysoxic to anoxic as evidenced by the cross-plot of V/Cr vs. V/(V + Ni); (iii) the water column environment was a deep, fresh-water lake, further confirming the moist paleoclimate and reducing environment; and (iv) the high TOC contents of the black shales are attributed to inputs from hydrothermal fluids as evidenced by the samples falling into or near to the hydrothermal area of the Ni/Cr vs. Ti plot and the Ti vs. V plot.

Apart from conventional gas in the middle-shallow formation in the Xihu depression in the East China Sea Basin, low permeability gas sandstone layers in the middle-deep formation have recently been discovered. On the basis of integrated analysis of reservoir petrology and diagenesis, geochemistry of gas and source rocks, basin numerical modeling, gold-tube pyrolysis experiment of rocks and fluid inclusion, a comprehensive investigation of the characteristics of low-permeability reservoirs, gas origin, generation and charge in the sub-structural belts (West Slope Belt and West Sub Sag) has been performed. Strong mechanical compaction, filar authigenic illite, siliceous and carbonate cements are key factors for the formation of low permeability reservoirs. The comprehensive analysis of molecular components, stable carbon isotope compositions of gases and light hydrocarbons indicated that the low permeability gases in the WSB are mainly coal-derived and can be divided into two types: (1) mature gases sourced from local coal-measure rocks in the Pinghu Formation, (2) exogenous highly mature gases sourced from the coal-measure rocks in the Pinghu Formation in the WSS. Mature gases were injected into the low permeability reservoirs in the middle-lower Pinghu Formation at approximately 2.8Ma∼0Ma. In the meantime, partial highly mature gases generated from source rocks in the WSS also migrated to the WSB. On the whole, the gas charge in the WSB is characterized by dual-sourcing and late-stage. The low permeability gases in the WSS almost are highly mature and composed of most coal-derived gases generated from local coal-measure rocks in the Pinghu Formation and a small amount of oil-derived gases generated from local dark mudstones containing sapropelic-type organic matters in the Pinghu Formation. In addition, mature coal-derived gases generated from source rocks in the lower Huagang Formation are also present but very limited. The charge of highly mature gases in the low permeability reservoirs in the lower Huagang Formation in the WSS occurred at approximately 3.9Ma∼0Ma.

Hydrous pyrolysis experiments were conducted to assess hydrocarbon generation and potential in three continental organic-rich shales at the highly-mature stage. The results of this study have important implications for deep petroleum exploration in China. The calcareous shale dominated by type-I kerogen reached its peak oil generation at a vitrinite reflectance (VR) of 1.5 %Ro, and entered the major stage of gas generation at a VR ranging from 1.50 to 2.44 %Ro. The high HI, low S2 and low atomic H/C ratio revealed that the calcareous shale has some potential for hydrocarbon generation at a VR greater than 2.44 %Ro. The mudstone with type-II kerogen reached its peak oil generation at a VR of 2.5 %Ro. The high atomic H/C ratio, but low HI and S2 indicated that mudstone may retain some hydrocarbon potential. The carbonaceous mudstone dominated by type-III kerogen had still not reached its peak of hydrocarbon generation at a VR of 3.12 %Ro. The low dryness of the gaseous hydrocarbon yields shows that the carbonaceous mudstone was still in the primary gas generation stage. The high values of S2 and atomic H/C fraction, but low HI, revealed that the carbonaceous mudstone may retain a large hydrocarbon generation potential at higher maturity stages. Our results suggested that the continental type-I and -II kerogen may have potential for shale gas and deep petroleum generation, while the continental type-III kerogen retained good potential for yielding deep natural gas.

For exploration and potential evaluation of deep shale reservoirs with high maturity, hydrocarbon generation and pore evolution of muddy shale in deep high evolution stage were investigated by the high-temperature high-pressure simulation experiment. Results indicated that under high pressure condition, nano-scale micropores in organic matter-rich muddy shale constantly increased as rise of temperature and pressure, leading to increase of shale porosity. However, in the high mature-overmature stage, shale porosity decreased with further increase of temperature and pressure. In contrast to micropores, micro-scale capillary pores and megapores in shale constantly decreased as rise of simulation temperature or pressure, indicating that deep-burial reservoirs was not favorable for free-gas storage; but significant increase of micropores and surface area during this stage could make up for a loss of adsorbed natural gas in shale due to decrease of adsorption capacity which was induced by increase of temperature and pressure, thus leading to high shale gas potential in deep layers. A large number of secondary micropores were developed in the simulated samples such as pyrite and dolomite, demonstrating that shale clasts and mineral matrix could also form abundant secondary micropores during the deep evolution stage; during the evolution process, shale as hydrocarbon source rock could generate a large amount of acidic fluid which was favorable for development of secondary porosity.

Based on abundant petrophysical property data of rocks and sedimentary and tectonic background,digenesis controlling development of abnormal high porosity zones in Yacheng area in the western Qiongdongnan basin were comprehensively investigated using cast thin sections,geochemistry data and fluid inclusion technology.It is found that digenesis controlling the development of the three abnormal high porosity zones in Yacheng area are different,which are organic acid corrosion and meteoric water leaching,thermal fluid corrosion and overpressure maintenance caused by gas generation,respectively.The results indicate that there are three abnormal high porosity zones,distributing in 2 400-3 100 m,3 600-4 100 m and 4 500-4 800 m of Yacheng area.The genesis of the first abnormal high porosity zone stems from the corrosion from organic acid and meteoric water.Feldspars and carbonate cements are corroded by both organic acid released from organic minerals in the early stage and meteoric water to generate secondary porosity.The chlorite cladding almost has no contribution to the development of the abnormal zone.Thermal fluid gives rise to the formation of the second abnormal high porosity zone.The thermal fluid activities make source rocks mature rapidly,therefore the organic acid generation period is extended,and more hydrogen ions are released due to smectite transferring into illite rapidly.Deep fluids carrying acidic components with strong flow lead to not only leaching of reservoir but also the rapid migration of the aluminum ions.The higher temperature and pressure promote erosion effects of reservoir,and the solubility is increased.The genesis of the third abnormal high porosity zone belongs to the type of overpressure maintenance.The compaction and development of authigenic minerals are effectively inhibited by strong overpressure,thus the reservoir porosity is preserved.Besides,the thermal fluids discharged upward by overpressure system cause the loss of silica which give rise to little development of authigenic quartz.The development of illite is also prohibited by the smectite transferring into illite ahead of time and overpressure.Natural gas charging in the study area occurs late.The development of authigenic minerals including quartz are not restrained by hydrocarbons emplacement.However,strong overpressure caused by abundant gas generation due to the rapid subsidence in Qiongdongnan basin indirectly contributes to the development of the third abnormal high porosity zone.

YC21-1 is a gas-bearing structure found within the Yanan sag in the Qiongdongnan Basin, South China Sea. While the structure bears many geological similarities to the nearby YC13-1 gas field, it nevertheless does not contain commercially viable gas volumes. The main reservoirs of the YC21-1 structure contain high overpressures, which is greatly different from those of the YC13-1 structure. The pressure coefficients from drillstem tests, wireline formation tests and mud weights are above 2.1. Based on well-log analysis, illite content and vitrinite reflectance data of mudstones in well YC21-1-2, combining with tectonic and sedimentation characteristics, the timing and causes of overpressure generation are here interpreted. The results indicate the existence of two overpressure segments in the YC21-1 structure. The first overpressure segment resides mainly within the lower and the middle intervals of the Yinggehai Formation, and is interpreted to have been mainly caused by clay diagenesis, while disequilibrium compaction and hydrocarbon generation may also have contributed to overpressure generation. The second overpressure segment comprising the Sanya Formation (Pressure transition zone) and the Lingshui and Yacheng Formations (Hard overpressure zone) is interpreted to owe its presence to kerogen-to-gas cracking. According to petrography, homogenization temperature and salinity of fluid inclusions, two stages of oil-gas charge occurred within the main reservoirs. On the basis of overpressure causes and oil-gas charge history, combining with restored tectonic evolution and fluid inclusion characteristics, a complex accumulation and leakage process in the YC21-1 gas bearing structure has been interpreted. Collective evidence suggests that the first oil charge occurred in the Middle Miocene (circa 16.3–11.2 Ma). Small amount of oil generation and absence of caprocks led to the failure of oil accumulation. Rapid subsidence in the Pliocene and Quaternary gave rise to a sharp increase in geotemperature over a short period of time, leading to prolific gas-generation through pyrolysis and, consequently, overpressure within the main reservoirs (the second overpressure segment). During this period, the second gas charge occurred in the Pliocene and Quaternary (circa 4.5–0.4 Ma). The natural gas migrated in several phases, consisting of free and water soluble phases in a high-pressure environment. Large amounts of free gas are considered to have been consumed due to dissolution within formation water in highly pressured conditions. Water soluble gas could not accumulate in high point of structure. When the pore-fluid pressures in main reservoirs reached the fracture pressure of formation, free gas could leak via opened fractures within cracked caprocks. A repeated fracturing of caprocks may have consumed natural gas stored in formation water and have made water-soluble gas unsaturated. Therefore, the two factors including caprocks fracturing and dissolution of formation water are interpreted to be mainly responsible for the failure of natural gas accumulation in the YC21-1 structure.

The hydrocarbon source rock development of the Yanchang formation in the Ordos Basin is closely related to the hydrothermal fluid activities.A total of 87 core samples were collected continuously for the high resolution element geochemical analysis.The results show that the high-quality hydrocarbon source rocks generally belong to atypical hydrothermal sedimentation with more terrigenous input,but the intensity of hydrothermal input became stronger during the Chang 7-3 period when the high-quality source rocks deposited.The correlation coefficients between the hydrothermal index Al/(Al + Fe+ Mn) or (Fe + Mn)/Ti ratio and TOC abundance are as high as-0.89 and 0.89,respectively,indicating that the hydrothermal sedimentation is closely related to the source rocks,i.e.increasing hydrothermal input intensity increases organic matter abundance in the hydrocarbon source rocks.The correlation coefficients between Al/(Al+Fe+ Mn) ratio and P/Al,P/Ti,TS content are-0.81,-0.80 and-0.89,respectively,suggesting the correlation of the hydrothermal sedimentation and hydrocarbon source rock may be due to hydrothermal activities.Such activities can promote surface productivity and anoxic condition in lake bottom,providing sufficient organic matter source and good preservation conditions in the process of hydrocarbon source rock development.Studies show that hydrothermal sedimentation are potential organic-rich hydrocarbon source rocks,and correlation analysis of quantitative elemental indices is an effective way to uncover the relationship between hydrothermal sedimentation and source rocks.

The relationship between overpressure and hydrocarbon accumulation was investigated using fluid inclusions, basin simulation and organic geochemistry. The results show that oil-gas in Pinghu structural belt is mainly derived from coal-measure source rocks in Pinghu formation. The main oil-gas accumulation occurred in late stage which is approximately consistent with the forming time of overpressure resulted by hydrocarbon generation. Besides, oil-gas pools are distributed near top overpressured surface. Overpressure is closely linked to hydrocarbon accumulation. The thermal anomaly from vitrinite reflectance, geotemperature gradient and homogenization temperatures of fluid inclusion, abnormal fluid pressure from physical property of reservoir, fluid inclusion with non-homogeneous capture and gas chimney, and abnormal components from light hydrocarbon indicate that efficient rapid fluid flow is controlled by overpressure. The discharging of high-pressure fluids induces opening of faults and provides power of fluid migration.

In order to find out the distribution regularities of organic matter abundance of Yanchang Formation in Ordos Basin,five typical drilling wells of Huachi,Heshui,Zhidan,Yaoqu and Yichuan in the southern basin were chosen,the spatial distribution of TOC contents of Chang 9 to Chang 4+5 sections of the wells and their controlling factors have been studied through the quantitative recovery method based on logging data.Results show that the TOC contents of well Li 94 and well Ning 36 mainly are "good" and "very good" in hydrocarbon source rock evaluation standard,while the TOC contents are "fair" and "good" in well Dan 48,well Wang 22 and well YK1.In the areas of well Li 94,well Ning 36 and well YK1,the organic matter enrichment layer is mainly concentrated in Chang 7 section,the continuous thickness of "very good" hydrocarbon source rock is up to 30 m.And in the area of well Dan 48,the organic matter enrichment layer is concentrated in Chang 9 section,the continuous thickness of "very good" hydrocarbon source rock is about 20 m,which deposited in the highstand systems tract of the stratigraphic sequence Ⅰ or Ⅱ in Yanchang Formation,whereas there is no significant organic matter enrichment section in well Wang 22.Studies suggest that the distribution and evolution of sedimentary facies was the main controlling factor of the different spatial distribution of organic matter abundance,volcanic activities and sedimentation rate aggravated the spatial difference of organic matter abundance,and the bottom thermal fluid activities and ancient climate conditions likely had a certain influence on the organic matter abundance differences of Yanchang Formation.

Hydrothermal sedimentation occurred in the Triassic Yanchang Formation, Ordos Basin, China. However, their macroscopic features at the scale of the stratum and hydrothermal sources still lack correlational research. This paper performed element geochemical study on a large number of core samples collected from the Yanchang Formation of a new drilling well located in the south Ordos Basin. The SiO2/(K2O + Na2O) vs. MnO/TiO2 crossplot and Fe vs. Mn vs. (Cu + Co + Ni) × 10 ternary diagram demonstrate that the Yanchang stratum in the study area has, in general, hydrothermal components. The Al/(Al + Fe + Mn) and (Fe + Mn)/Ti ratios of the core samples range from 0.34 to 0.84 and 4.81 to 50.54, averaging 0.66 and 10.67, respectively, indicating that the stratum is a set of atypical hydrothermal sedimentation with much terrigenous input. Data analysis shows that the hydrothermal source in the study area was from the deep North Qinling Orogen around the south margin of the basin, where some active tectonic and volcanic activities took place, rather than from the relatively stable internal basin. Early Indosinian movement and volcanic activities activated basement faults around the southern margin of the basin, providing vents for the deep hydrothermal fluid upwelling. The hydrothermal indicators suggest that the study area experienced 4 episodes of relatively stronger hydrothermal activity, namely during the Chang 10, Chang 9–1, Chang 7–3 and Chang 6–2 periods. We also propose a new hydrothermal sedimentation model of hydrothermal fluids overflowing from basin margin faults, for the Yanchang Formation, which is reported here for the first time.

The Triassic Yanchang Formation is the main source rocks for Mesozoic oil in Ordos Basin. The formation includes 10 oil-bearing beds (Ch 1–Ch 10), that each can be further divided into two to three intervals. Abundant C12–C14 and C15–C16 bicyclic alkanes have been detected in the formation in the Xifeng oilfield, Ordos Basin. The C12–C14 group is dominated by C12 and C13, and the C15–C16 group contains abundant C15. The groups show three distribution patterns: A) the C12–C14 group is the major component in the non-source rocks of the Ch 7-1 and Ch 8-1 intervals; B) both groups are abundant and are common in source rocks of the Ch 7-3 interval; and C) the C15–C16 group is the major component in source rocks of the Ch 7-3 interval and also in sediments that contain type Ⅰ or partial sapropel type Ⅱ1 organic matter (OM) in the Ch 7-2 and Ch 8-1 intervals. Although thermal maturities of the source rocks in the Ch 7 section are similar, they show significant differences with respect to the drimane isomerisation index, which indicates that the drimane rearrangement is controlled by thermal evolution of the sediments, but may also be closely related to the depositional environment. This study determined that reducing environments are more conducive to preservation of drimane than oxic environments. The drimane isomerisation index and the value of the hopane parameter Tm/Ts are positively correlated. The parameter Tm/Ts varies over a wide range within the sequence, and the large variations may be a result of terrigenous OM input by turbidity currents and/or gravity flows, mixed with the autochthonous sediments. Abundant homodrimane in both source rocks may reflect reducing environments in deep lakes and major input of higher plant OM. Organic-rich shale and oil shale in the Ch 7-3 interval of the Yanchang Formation are the primary sources of oil in reservoirs in the Xifeng area. The crude oil is rich in bicyclic alkanes that are dominated by C15–C16 as source rocks with pattern C for bicyclic alkanes, which indicates an origin mainly from the Ch 7-3 interval. The main peaks in all of the crude oils are associated with 8β(H)-drimane and lower abundance of rearranged drimane. However, most of the source rocks have a main peak associated with 8β(H)-homodrimane or rearranged drimane. Weak microbial action, selective degradation and water washing may be the cause of the significant difference in bicyclic sesquiterpane composition between the crude oil and the source rocks. The result suggests that oil-source correlations based on the bicyclic sesquiterpanes are questionable.

Hydrous pyrolysis experiments were conducted on immature petroleum source rocks to define the roles of pressure and hydrocarbon expulsion in deep petroleum formation. This study can contribute to estimating the deep oil and natural gas prospects of lacustrine type-I kerogen and has important implications for deep petroleum exploration. The simulation temperature was 450 degrees C and the heating duration was 48 h. Water pressure ranged between 50 and 1200 bar, and lithostatic pressure ranged between 125 and 2000 bar. Under semi-closed conditions, increasing water pressure leads to more oil and less gaseous hydrocarbons being generated in the source rocks. The dryness of the hydrocarbon gas primarily confirms that increasing water pressure decreases the cracking magnitude of oil, which may indicate that high water pressures retard oil cracking. The decreasing contents of S-2, HI and H/C in the solid residue confirm that high water pressure enhances the efficiency of hydrocarbon generation. Oil cracking is enhanced in the 125-625 bar lithostatic pressure range, probably because the pyrolysis conditions gradually approach those of a closed-system. The increasing gaseous hydrocarbon yields also confirm the accelerated cracking of oil within this pressure range. As lithostatic pressure increased from 625 to 2000 bar, the decreasing trends in oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was retarded by high pressure within the closed system. The values of S-2, HI, H/C, R-0 and T-max in solid pyrolysis residue confirm that high lithostatic pressure reduces the efficiency of hydrocarbon generation and maturation. Furthermore, hydrocarbon expulsion greatly impacts hydrocarbon generation within the source rocks. Increasing water pressure increases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to gradually approach an open system; this phenomenon lowers the gas yields but increases oil yields. Increasing lithostatic pressure from 125 to 625 bar decreases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to steadily approach a closed system, thereby lowering the oil yield but increasing gas yield. The results demonstrate that different pressures clearly have different effects on hydrocarbon generation in the source rock, and hydrocarbon expulsion also has a significant influence on hydrocarbon generation in source rock. More importantly, this study shows that the lacustrine type-I kerogen has a good potential to yield deep oil and natural gas. (C) 2016 Elsevier B.V. All rights reserved.

为了解压力对有机质热演化和成烃过程的影响,利用高压生烃模拟仪,在一定半开放体系中,对采自钻孔的泥质烃源岩样品进行了恒压与增压2个系列的生烃模拟实验.恒压系列中,沥青、热解油和气态烃产率高峰分别出现在350℃、520℃和520℃,产率依次为6.17mg/g、12.07mg/g和4.14mL/g,对应镜质体反射率(RO)分别为0.9％、3.0％和3.0％,排烃次数分别为4次、21次和21次.增压系列中,沥青、热解油和气态烃产率高峰分别出现在350℃、500℃和520℃,产率依次为12.56mg/g、24.87mg/g和2.59mL/g,对应RO值分别为1.1％、3.1％和3.1％,对应排烃次数分别为5次、43次和44次.表明在半开放体系中,排烃次数受到温度和排烃压力阈值的共同控制,温度升高引起生烃强度增加,在同一排烃压力阈值条件下,体系内压力不断上升,达到排烃压力阈值上限,导致排烃次数增加,而排烃次数增加可能有利于液态烃的形成.流体压力的升高可能会促进沥青和热解油的形成,导致液态烃产率升高.同时,流体压力的升高也可能不利于气态烃的形成,会降低气态烃产率.流体压力对有机质RO值的影响在不同温度阶段不尽相同,400～500℃区间RO值随流体压力升高明显增加.

The microscopic fluorescence spectroscopy has become a mature technology of fluid inclusions test and analysis system, which is used to distinguish different types of crude oil and oil inclusions. These would be the important basis to study the history of hydrocarbon accumulation of petroleum basins. The mixture of crude oil from different sources could occur in migration and accumulation process. In order to effectively identify the type of geological process, mixing ratio of crude oil experiment has been carried out. This study result shows that mixing of crude oil make fluorescence color and spectral parameters(λmax, QF535 and CIE-XY) change nonlinearly. Fluorescence spectral parameters of mixed oil is between end member oil A and B. The greater A or B ratio of mixed oil, the closer to A or B. Fluorescence color of mixed oil show nonlinear and gradual change in CIE-XY chromaticity diagram. Variation of spectral spectrum shape show that single peak is changed into double and three peaks. The relationship between QF535 and degree of mixing could calculate quantitatively relative contribution. Mixing different types of crude oil make spectral spectrum shape changes, which present characteristics of two peaks and three peaks but not unimodal peak. The main and subsidiary wavelength reserve wavelength information of end member oils. Based on variation characteristics of fluorescence spectrum, there are three different types of oil including blue, blue-green and yellow fluorescing oil filling in the bottom member of Pinghu formation in A gas field. At the same time, there also was a mixing process of blue-green fluorescing oil and yellow fluorescing oil. The degree of mixing is 47%~55%.

基于琼东南盆地西部崖城地区10余口钻井的实测钻井资料,以及流体包裹体、激光拉曼探针、古压力热动力学模拟、有机地球化学、阴极发光、铸体薄片和碳酸盐胶结物碳氧同位素组成等多项测试分析,剖析了超压顶界面分布以及附近的泄压带流体活动特征,同时揭示了流体活动造成泄压带岩场响应.研究区泄压带可能位于超压顶面附近地层;地层测试、泥浆密度、测井曲线和速度谱资料确定了崖城区现今超压顶面深度主要分布在3 000～4000m,而且由构造高部位向低部位加深;各井超压顶面附近的泄压影响范围不同,具体范围可由镜质体反射率R.得到.现今超压顶面与古超压顶面(泄压流体排放期)深度变化较小.泄压带流体具有相对高温高压、含有酸性和烃类等特征,流体活动使得泄压带成岩场的温压条件和孔隙流体介质发生变化从而影响了水-岩作用;主要表现为:①泄压带地层的R.和黏土矿物出现提前转变趋势;②有机质Tmax异常小和S1/(S1+S2)异常大;③泄压带储层发生的热流体酸性溶蚀导致次生孔隙带发育;④长石颗粒钠长石化,自生石英和碳酸盐胶结物异常发育,其为深部超压有机流体排放的产物.总之,研究区超压顶面附近的泄压带可能为天然气与优质储层及盖层耦合有利聚集带,是今后琼东南盆地天然气勘探的现实区域.

The applications of Confocal Scanning Laser Microscopy ( CSLM) in petroleum geology are still under developing. In order to effectively develop the function of the equipment in the petroleum geology, the concrete application examples of CSLM about pore throat characterization in reservoir and fluid inclusions were demonstrated in this paper. Taking rock thin section of tight sandstone reservoir in QY1 well in Xihu sag, East China Sea Basin as an example, the pore diameter, fabric, morphology and hydrocarbon existence state were calculated and observed by CSLM. At the same time, the porosity calculation method was improved, so the precision was improved. Taking fluid inclusion slice of silurian reservoir of 904 well in Tarim Basin as an example, the measurement method of gas liquid ratio of oil inclusions was improved by reducing the fluorescence cover effect of oil inclusions to improve the precision. The paleo pressure value was restored by thermodynamic simulation software.

In order to investigate the process of thermal evolution and hydrocarbon generation of organic matter,mudstone source rock from drilling was pyrolyzed in simulation with con-pressure and hetero-pres-sure experiments in semi-open system high pressure instrument (HTHP).In con-pressure experiments, peak of bitumen,oil,gaseous hydrocarbon yields appeared at 350℃,450℃ and 520℃ respectively,and yields were,in order,1.82mg/g,4.86mg/g and 2.67mL/g.The corresponding R O of residues were 0.68%, 1.72% and 3.0%.In hetero-pressure experiments,peak of bitumen,oil,gaseous hydrocarbon yields appeared at 350℃,450℃ and 520℃ respectively,and yields were,in order,0.56mg/g,5.41 mg/g and 2.61 mL/g.The corresponding R O of residues were 0.56%,2.42% and 2.74%.Results demonstrate that increasing the fluids pressure might enhance source rocks to yield oil and reduce bitumen,but it might increase liquids yields.At the same time,increasing fluid pressure might reduce the yield of gaseous hydrocarbons,causing the nega-tive influence of gaseous hydrocarbons generation.This phenomenon indicated that fluids pressure had dif-ferent influences on the thermal evolution and hydrocarbon generation of organic matter in different stage of thermal evolution.Besides,TOC of the residues in hetero-pressure experiments was lower than the resi-dues in con-pressure experiments,the index of generation potential S2 、I H 、H/C had the same variation trend.This demonstrates that the high fluids pressure might reduce the generation potential of residues and enhance the efficiency of organic matters generating hydrocarbons,during it increase liquids yields.T max and R O were affected differently by fluids pressure in different stage of thermal evolution,T max and R O in-creased obviously in the stage of organic matter yielding oil rapidly.

尽管通过测井数据预测烃源岩有机碳含量(TOC)具有经济快速的明显优势,但由于不同地区及地层的特殊性,其预测误差限制了该方法的广泛应用.利用前人提出的预测烃源岩TOC含量的自然伽马测并法、体积密度测井法、多元回归分析法和BP神经网络模型,结合鄂尔多斯盆地延长组的地质特征建立了研究区TOC含量预测的经验公式和模型.优选认为BP模型为延长组TOC含量预测精度最高的方法,并将其应用于盆地南部YK1井延长组,得到9 220个样点的TOC值,辨识出4段连续厚度大于10m的有效烃源岩,分别位于长19段、长37段、长27段和长17段,并且长27—长37段为TOC含量最高的优质层段.研究发现,这些有效烃源岩层段均不同程度地发育油页岩,并且同一层段TOC含量预测值在不同地区的钻井中可能出现明显的差异,这与延长组不同沉积时期古湖泊沉积相的分布和差异相一致.